form10-q33108.htm

SIERRA PACIFIC RESOURCES

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2008

CONTENTS


PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements

Sierra Pacific Resources —
Consolidated Balance Sheets — March 31, 2008 and December 31, 2007			3
Consolidated Statements of Operations — Three Months Ended March 31, 2008 and 2007			4
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2008 and 2007			5

Nevada Power Company —
Consolidated Balance Sheets — March 31, 2008 and December 31, 2007			6
Consolidated Statements of Operations — Three Months Ended March 31, 2008 and 2007			7
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2008 and 2007			8

Sierra Pacific Power Company —
Consolidated Balance Sheets — March 31, 2008 and December 31, 2007			9
Consolidated Statements of Operations — Three Months Ended March 31, 2008 and 2007			10
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2008 and 2007			11

Condensed Notes to Consolidated Financial Statements			12

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
Sierra Pacific Resources			31
Nevada Power Company			35
Sierra Pacific Power Company			41

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk			49

ITEM 4. Controls and Procedures			50

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings			50

ITEM 1A. Risk Factors			52

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			53

ITEM 3. Defaults Upon Senior Securities			53

ITEM 4. Submission of Matters to a Vote of Security Holders			53

ITEM 5. Other Information			53

ITEM 6. Exhibits			54

Signature Page and Certifications			55

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	8,511,562	$	8,468,711
Less accumulated provision for depreciation			2,522,129		2,526,379
			5,989,433		5,942,332
Construction work-in-progress			1,153,010		1,068,666
			7,142,443		7,010,998

Investments and other property, net			30,932		31,061

Current Assets:
Cash and cash equivalents			120,757		129,140
Accounts receivable less allowance for uncollectible accounts:
	2008-$30,360, 2007-$36,061		374,560		434,359
Deferred energy costs - electric (Note 1)			56,977		75,948
Materials, supplies and fuel, at average cost			110,193		117,483
Risk management assets (Note 5)			178,938		22,286
Deferred income taxes			45,313		43,295
Other			44,291		45,909
			931,029		868,420
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			179,959		205,030
Regulatory tax asset			264,809		267,848
Regulatory asset for pension plans			132,733		133,984
Other regulatory assets			777,550		758,287
Risk management assets (Note 5)			15,872		12,429
Risk management regulatory assets - net (Note 5)			-		26,067
Unamortized debt issuance costs			62,931		65,218
Other			110,551		85,408
			1,544,405		1,554,271
TOTAL ASSETS		$	9,648,809	$	9,464,750

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,004,497	$	2,996,575
Long-term debt			4,173,617		4,137,864
			7,178,114		7,134,439
Current Liabilities:
Current maturities of long-term debt			110,168		110,285
Accounts payable			326,630		357,867
Accrued interest			72,606		69,485
Accrued salaries and benefits			27,317		35,020
Current income taxes payable			7,944		3,544
Risk management liabilities (Note 5)			2,762		39,509
Accrued taxes			8,700		8,336
Deferred energy costs-electric (Note 1)			28,782		17,573
Deferred energy costs - gas (Note 1)			14,965		11,369
Other current liabilities			81,588		65,991
			681,462		718,979
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			857,891		852,630
Deferred investment tax credit			28,151		28,895
Regulatory tax liability			27,650		28,445
Customer advances for construction			99,342		100,125
Accrued retirement benefits			85,784		77,525
Deferred/risk management liabilities (Note 5)			4,316		7,369
Risk management regulatory liability - net (Note 5)			173,476		-
Regulatory liabilities			310,086		304,026
Other			202,537		212,317
			1,789,233		1,611,332
TOTAL CAPITALIZATION AND LIABILITIES		$	9,648,809	$	9,464,750

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended
	March 31,
	2008			2007

OPERATING REVENUES:
Electric	$	719,450		$	671,044
Gas		85,594			85,120
Other		7			267
		805,051			756,431
OPERATING EXPENSES:
Operation:
Purchased power		183,856			178,904
Fuel for power generation		221,608			228,154
Gas purchased for resale		66,896			71,646
Deferral of energy costs - electric - net		54,282			40,793
Deferral of energy costs - gas - net		2,203			(1,945	)
Other		91,675			84,747
Maintenance		23,122			23,745
Depreciation and amortization		62,070			56,233
Taxes:
Income tax (benefits)		8,619			(755	)
Other than income		13,907			12,979
		728,238			694,501
OPERATING INCOME		76,813			61,930

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		11,957			6,567
Interest accrued on deferred energy		1,236			4,614
Carrying charge for Lenzie		-			10,082
Reinstated interest on deferred energy		-			11,076
Other income		13,672			7,306
Other expense		(3,027	)		(4,916	)
Income taxes		(8,089	)		(11,383	)
		15,749			23,346
Total Income Before Interest Charges		92,562			85,276

INTEREST CHARGES:
Long-term debt		69,955			66,449
Other		7,701			8,554
Allowance for borrowed funds used during construction		(9,152	)		(5,334	)
		68,504			69,669

NET INCOME APPLICABLE TO COMMON STOCK	$	24,058		$	15,607

Amount per share basic and diluted -
Net Income applicable to common stock	$	0.10		$	0.07

Weighted Average Shares of Common Stock Outstanding - basic		233,836,234			221,245,427
Weighted Average Shares of Common Stock Outstanding - diluted		234,321,972			221,701,854

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income applicable to common stock	$	24,058		$	15,607
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		62,070			56,233
Deferred taxes and deferred investment tax credit		9,482			5,165
AFUDC		(11,957	)		(6,567	)
Amortization of deferred energy costs - electric		56,727			36,134
Amortization of deferred energy costs - gas		(637	)		478
Deferral of energy costs - electric		(1,476	)		228
Deferral of energy costs - gas		4,233			(2,330	)
Carrying charge on Lenzie plant		-			(10,082	)
Reinstated interest on deferred energy		-			(11,076	)
Other, net		(9,000	)		(3,637	)
Changes in certain assets and liabilities:
Accounts receivable		59,799			48,272
Materials, supplies and fuel		7,289			(617	)
Other current assets		1,617			6,852
Accounts payable		(16,128	)		8,277
Accrued Retirement Benefits		4,537			235
Other current liabilities		5,331			16,895
Risk Management assets and liabilities		(352	)		538
Other deferred assets		(9,484	)		-
Other regulatory assets		(14,313	)		-
Other assets		745			-
Other liabilities		(10,859	)		497
Net Cash from Operating Activities		161,682			161,102

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related AFUDC)		(225,465	)		(294,930	)
Customer advances for construction		(783	)		5,723
Contributions in aid of construction		32,475			19,686
Investments and other property - net		4,392			(43	)
Net Cash used by Investing Activities		(189,381	)		(269,564	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		40,000			174,451
Retirement of long-term debt		(4,364	)		(28,944	)
Sale of common stock		2,253			3,771
Proceeds from exercise of stock option		225			-
Dividends paid		(18,798	)		-
Net Cash from Financing Activities		19,316			149,278

Net Increase (Decrease) in Cash and Cash Equivalents		(8,383	)		40,816
Beginning Balance in Cash and Cash Equivalents		129,140			115,709
Ending Balance in Cash and Cash Equivalents	$	120,757		$	156,525

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	68,326		$	54,333
Income taxes	$	3,544		$	4,578

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

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	5,581,800	$	5,571,492
Less accumulated provision for depreciation			1,393,883		1,407,334
			4,187,917		4,164,158
Construction work-in-progress			659,590		576,127
			4,847,507		4,740,285

Investments and other property, net			19,534		19,544

Current Assets:
Cash and cash equivalents			51,113		37,001
Accounts receivable less allowance for uncollectible accounts:
	2008-$27,158 , 2007-$30,392		238,290		274,242
Deferred energy costs - electric (Note 1)			56,977		75,948
Materials, supplies and fuel, at average cost			64,048		68,671
Risk management assets (Note 5)			131,420		16,078
Deferred income taxes			17,334		2,383
Other			28,943		28,352
			588,125		502,675
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			179,959		205,030
Regulatory tax asset			165,664		165,257
Regulatory asset for pension plans			85,803		86,909
Other regulatory assets			535,870		524,460
Risk management assets (Note 5)			11,715		9,069
Risk management regulatory assets - net (Note 5)			-		17,186
Unamortized debt issuance costs			35,349		36,551
Other			90,912		70,403
			1,105,272		1,114,865
TOTAL ASSETS		$	6,560,438	$	6,377,369

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,421,671	$	2,376,740
Long-term debt			2,564,629		2,528,141
			4,986,300		4,904,881
Current Liabilities:
Current maturities of long-term debt			8,616		8,642
Accounts payable			229,054		231,205
Accounts payable, affiliated companies			26,097		32,706
Accrued interest			49,387		41,920
Dividends declared			-		10,907
Accrued salaries and benefits			12,872		16,881
Current income taxes payable			7,944		3,544
Intercompany Income taxes payable			10,299		15,403
Risk management liabilities (Note 5)			1,481		26,982
Accrued taxes			5,031		4,529
Other current liabilities			66,780		50,902
			417,561		443,621
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			587,424		585,168
Deferred investment tax credit			10,877		11,169
Regulatory tax liability			9,692		10,038
Customer advances for construction			57,011		58,890
Accrued retirement benefits			32,779		25,693
Risk management liabilities (Note 5)			3,477		5,116
Risk management regulatory liability - net (Note 5)			127,389		-
Regulatory liabilities			169,549		168,381
Other			158,379		164,412
			1,156,577		1,028,867

TOTAL CAPITALIZATION AND LIABILITIES		$	6,560,438	$	6,377,369

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

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2008			2007
OPERATING REVENUES:
Electric	$	469,172		$	418,165

OPERATING EXPENSES:
Operation:
Purchased power		93,750			95,594
Fuel for power generation		164,021			164,085
Deferral of energy costs-net		45,775			26,932
Other		57,095			50,839
Maintenance		16,650			17,464
Depreciation and amortization		40,630			35,761
Taxes:
Income tax (benefits)		2,132			(8,212	)
Other than income		8,322			7,734
		428,375			390,197
OPERATING INCOME		40,797			27,968

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,858			3,098
Interest accrued on deferred energy		1,794			3,849
Carrying charge for Lenzie		-			10,082
Reinstated interest on deferred energy		-			11,076
Other income		5,747			5,121
Other expense		(1,361	)		(2,042	)
Income taxes		(4,391	)		(10,578	)
		8,647			20,606
Total Income Before Interest Charges		49,444			48,574

INTEREST CHARGES:
Long-term debt		40,997			39,706
Other		5,831			6,836
Allowance for borrowed funds used during construction		(5,355	)		(2,550	)
		41,473			43,992

NET INCOME	$	7,971		$	4,582


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

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	7,971		$	4,582
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		40,630			35,761
Deferred taxes and deferred investment tax credit		(14,443	)		(2,645	)
AFUDC		(6,858	)		(3,098	)
Amortization of deferred energy costs		46,765			24,082
Deferral of energy costs		(2,723	)		(844	)
Carrying charge on Lenzie plant		-			(10,082	)
Reinstated interest on deferred energy		-			(11,076	)
Other, net		(4,685	)		(4,419	)
Changes in certain assets and liabilities:
Accounts receivable		35,952			33,908
Materials, supplies and fuel		4,623			(109	)
Other current assets		(590	)		675
Accounts payable		(18,882	)		23,267
Accrued retirement benefits		4,396			3,539
Other current liabilities		13,716			12,649
Risk management assets and liabilities		(553	)		(458	)
Other deferred assets		(9,484	)		-
Other regulatory assets		(9,099	)		-
Other assets		(1,449	)		-
Other liabilities		(8,426	)		(4,439	)
Net Cash from Operating Activities		76,861			101,293

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related AFUDC)		(156,302	)		(188,196	)
Customer advances for construction		(1,879	)		5,330
Contributions in aid of construction		28,057			12,302
Investments and other property - net		2,821			(39	)
Net Cash used by Investing Activities		(127,303	)		(170,603	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		40,000			125,000
Retirement of long-term debt		(3,539	)		(3,213	)
Additional investment by parent company		53,000			-
Dividends paid		(24,907	)		(13,472	)
Net Cash from Financing Activities		64,554			108,315

Net Increase in Cash and Cash Equivalents		14,112			39,005
Beginning Balance in Cash and Cash Equivalents		37,001			36,633
Ending Balance in Cash and Cash Equivalents	$	51,113		$	75,638

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	34,751		$	32,572
Income taxes	$	3,544		$	4,550

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	2,929,762	$	2,897,219
Less accumulated provision for depreciation			1,128,246		1,119,045
			1,801,516		1,778,174
Construction work-in-progress			493,420		492,539
			2,294,936		2,270,713

Investments and other property, net			452		570

Current Assets:
Cash and cash equivalents			55,092		23,807
Accounts receivable less allowance for uncollectible accounts:
	2008-$3,202; 2007 - $5,669		136,084		160,014
Materials, supplies and fuel, at average cost			46,129		48,799
Risk management assets (Note 5)			47,518		6,208
Deferred income taxes			22,258		17,728
Other			15,204		17,255
			322,285		273,811
Deferred Charges and Other Assets:
Regulatory tax asset			99,145		102,591
Regulatory asset for pension plans			43,692		43,778
Other regulatory assets			241,680		233,827
Risk management assets (Note 5)			4,157		3,360
Risk management regulatory assets - net (Note 5)			-		8,881
Unamortized debt issuance costs			19,194		19,976
Other			19,290		19,017
			427,158		431,430
TOTAL ASSETS		$	3,044,831	$	2,976,524

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	1,037,364	$	1,001,840
Long-term debt			1,083,870		1,084,550
			2,121,234		2,086,390
Current Liabilities:
Current maturities of long-term debt			101,552		101,643
Accounts payable			73,254		94,722
Accounts payable, affiliated companies			15,025		19,288
Accrued interest			19,095		15,750
Dividends declared			-		5,333
Accrued salaries and benefits			12,491		14,830
Intercompany income taxes payable			11,950		2,479
Risk management liabilities (Note 5)			1,281		12,527
Accrued taxes			3,549		3,542
Deferred energy costs-electric (Note 1)			28,782		17,573
Deferred energy costs - gas (Note 1)			14,965		11,369
Other current liabilities			14,809		15,015
			296,753		314,071
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			269,944		267,801
Deferred investment tax credit			17,274		17,726
Regulatory tax liability			17,958		18,407
Customer advances for construction			42,331		41,235
Accrued retirement benefits			48,516		48,025
Risk management liabilities (Note 5)			839		2,253
Risk management regulatory liability - net (Note 5)			46,087		-
Regulatory liabilities			140,537		135,645
Other			43,358		44,971
			626,844		576,063
TOTAL CAPITALIZATION AND LIABILITIES		$	3,044,831	$	2,976,524

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2008			2007
OPERATING REVENUES:
Electric	$	250,278		$	252,879
Gas		85,594			85,120
		335,872			337,999
OPERATING EXPENSES:
Operation:
Purchased power		90,106			83,310
Fuel for power generation		57,587			64,069
Gas purchased for resale		66,896			71,646
Deferral of energy costs - electric - net		8,507			13,861
Deferral of energy costs - gas - net		2,203			(1,945	)
Other		33,505			32,848
Maintenance		6,472			6,281
Depreciation and amortization		21,440			20,472
Taxes:
Income tax		9,659			8,360
Other than income		5,528			5,186
		301,903			304,088
OPERATING INCOME		33,969			33,911

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,099			3,469
Interest accrued on deferred energy		(558	)		765
Other income		7,735			1,831
Other expense		(1,800	)		(2,014	)
Income taxes		(3,574	)		(1,211	)
		6,902			2,840
Total Income Before Interest Charges		40,871			36,751

INTEREST CHARGES:
Long-term debt		18,762			16,108
Other		1,622			1,459
Allowance for borrowed funds used during construction		(3,797	)		(2,784	)
		16,587			14,783

NET INCOME	$	24,284		$	21,968

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	24,284		$	21,968
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		21,440			20,472
Deferred taxes and deferred investment tax credit		9,629			1,142
AFUDC		(5,099	)		(3,469	)
Amortization of deferred energy costs - electric		9,962			12,052
Amortization of deferred energy costs - gas		(637	)		478
Deferral of energy costs - electric		1,247			1,072
Deferral of energy costs - gas		4,233			(2,330	)
Other, net		(2,789	)		1,881
Changes in certain assets and liabilities:
Accounts receivable		23,930			14,222
Materials, supplies and fuel		2,669			(510	)
Other current assets		2,050			5,960
Accounts payable		(500	)		(471	)
Accrued retirement benefits		(643	)		2,886
Other current liabilities		806			13,119
Risk management assets and liabilities		201			996
Other regulatory assets		(5,214	)		-
Other assets		2,193			-
Other liabilities		(294	)		(1,909	)
Net Cash from by Operating Activities		87,468			87,559

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related AFUDC)		(69,163	)		(106,734	)
Customer advances for construction		1,096			393
Contributions in aid of construction		4,418			7,384
Investments and other property - net		1,570			(8	)
Net Cash used by Investing Activities		(62,079	)		(98,965	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		-			49,451
Retirement of long-term debt		(771	)		(25,677	)
Investment by parent company		20,000			-
Dividends paid		(13,333	)		(6,736	)
Net Cash from Financing Activities		5,896			17,038

Net Increase in Cash and Cash Equivalents		31,285			5,632
Beginning Balance in Cash and Cash Equivalents		23,807			53,260
Ending Balance in Cash and Cash Equivalents	$	55,092		$	58,892

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	15,688		$	3,385
Income taxes	$	-		$	28

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

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 of Sierra Pacific Resources (SPR) include the accounts of SPR and its wholly-owned subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC) (collectively, the "Utilities"), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications (SPC) and Sierra Water Development Company (SWDC). The consolidated financial statements of NPC include the accounts of NPC and its wholly-owned subsidiary, Nevada Electric Investment Company (NEICO). The consolidated financial statements of SPPC include the accounts of SPPC and its wholly-owned subsidiaries, GPSF-B, Piñon Pine Corporation (PPC), Piñon Pine Investment Company, Piñon Pine Company, L.L.C. and Sierra Pacific Funding L.L.C. All significant intercompany transactions and balances have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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 SPR, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain all 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 SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the three months ended March 31, 2008, are not necessarily indicative of the results to be expected for the full year.

Deferral of Energy Costs

NPC and SPPC follow deferred energy accounting. See Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in NPC's and SPPC's 2007 Form 10-K, for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of March 31, 2008 (dollars in thousands):

	March 31, 2008
	NPC			SPPC			SPPC			SPR
Description	Electric			Electric			Gas			Total

Unamortized balances approved for collection in current rates

Reinstatement of deferred Energy (effective 6/07, 10 years)	$	176,340		$	-		$	-		$	176,340
Electric – NPC Period 5 (effective 8/06, 2 years)		32,138			-			-			32,138
Electric – SPPC Period 5 (effective 7/06, 2 years)		-			1,466			-			1,466
Electric – NPC Period 6 (effective 6/07, 14 months)		16,576			-			-			16,576
Electric – SPPC Period 6 (effective 7/07, 1 year)		-			3,553			-			3,553
Natural Gas (1) (effective 12/07, 1 year)		-			-			(654	)		(654	)
Western Energy Crisis Rate Case-NPC (effective 6/07, 3 years)		61,243			-			-			61,243
Balances pending PUCN approval(1)		(49,361	)		(35,055	)		(14,311	)		(98,727	)
Cumulative CPUC balance		-			1,254			-			1,254
Total	$	236,936		$	(28,782	)	$	(14,965	)	$	193,189

Current Assets
Deferred energy costs – electric	$	56,977		$	-		$	-		$	56,977
Deferred Assets
Deferred energy costs - electric		179,959			-			-			179,959
Current Liabilities
Deferred energy costs – electric		-			(28,782	)		-			(28,782	)
Deferred energy costs – gas		-			-			(14,965	)		(14,965	)
Total	$	236,936		$	(28,782	)	$	(14,965	)	$	193,189

(1)	Credit balances represent potential refunds to the Utilities’ customers.

Recent Pronouncements

SFAS 161

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB Statement No. 133 (“SFAS 161”) which is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The purpose of SFAS 161 is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. The Utilities are currently evaluating the additional disclosure requirements but do not expect their disclosure to change significantly.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as defined by SFAS 131, “Disclosure about Segments of an Enterprise and Related Information”); which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments 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. SPR 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 fuel, purchased power, and deferred energy costs, provides a measure of income available to support the other operating expenses of the Utilities. 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	NPC		SPPC		SPPC		SPPC		SPR			SPR
March 31, 2008	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	469,172	$	250,278	$	85,594	$	335,872	$	7		$	805,051

Energy Costs:
Purchased Power		93,750		90,106				90,106					183,856
Fuel for power generation		164,021		57,587				57,587					221,608
Gas purchased for resale						66,896		66,896					66,896
Deferred energy costs - net		45,775		8,507		2,203		10,710					56,485
	$	303,546	$	156,200	$	69,099	$	225,299				$	528,845

Gross Margin	$	165,626	$	94,078	$	16,495	$	110,573	$	7		$	276,206

Other		57,095						33,505		1,075			91,675
Maintenance		16,650						6,472					23,122
Depreciation and amortization		40,630						21,440					62,070
Taxes:
Income taxes		2,132						9,659		(3,172	)		8,619
Other than income		8,322						5,528		57			13,907

Operating Income	$	40,797					$	33,969	$	2,047		$	76,813


Three months ended	NPC			SPPC		SPPC			SPPC		SPR			SPR
March 31, 2007	Electric			Electric		Gas			Total		Other			Consolidated
Operating Revenues	$	418,165		$	252,879	$	85,120		$	337,999	$	267		$	756,431

Energy Costs:
Purchased Power		95,594			83,310					83,310					178,904
Fuel for power generation		164,085			64,069					64,069					228,154
Gas purchased for resale							71,646			71,646					71,646
Deferred energy costs - net		26,932			13,861		(1,945	)		11,916					38,848
	$	286,611		$	161,240	$	69,701		$	230,941				$	517,552

Gross Margin	$	131,554		$	91,639	$	15,419		$	107,058	$	267		$	238,879

Other		50,839								32,848		1,060			84,747
Maintenance		17,464								6,281					23,745
Depreciation and amortization		35,761								20,472					56,233
Taxes:
Income taxes		(8,212	)							8,360		(903	)		(755	)
Other than income		7,734								5,186		59			12,979

Operating Income	$	27,968							$	33,911	$	51		$	61,930

NOTE 3. REGULATORY ACTIONS

Pending Rate Cases

Nevada Power Company

NPC 2008 Deferred Energy Rate Case and BTER Update

In February 2008 NPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications, NPC requests to decrease rates by $116.3 million, a decrease of 5.04% while recovering $36 million of deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2008 and the going forward BTER became effective April 1, 2008.

NPC Seventh Amendment to 2006 Integrated Resource Plan (IRP)

In March 2008, NPC filed its 7th amendment to its’ 2007-2026 Integrated Resource Plan with the PUCN (“2006 Resource Plan”). Included in the amendment are several initiatives, all of which comport with the goal of providing clean, safe, and reliable electricity to NPC’s customers at reasonable and predictable prices. Significant 2006 Resource Plan amendment requests include:

·	Approval to construct a 500 MW (nominal) combined cycle unit at the existing Harry Allen site with a scheduled commercial operation date of June 1, 2011. The estimated cost of this project is approximately $682 million (excluding allowance for funds used during construction or “AFUDC”).

Several approvals related to the Ely Energy Center (“EEC”): first, to delay the required 2008 EEC Amendment filing to no later than April 2010; second, to update the budget for the development and permitting of EEC ($155 million through February 2010); and third, to revise the proposed EEC construction schedule to accommodate a June 1, 2015 in-service date for Unit 1 and June 1, 2016 in-service date for Unit 2.

·	Approval to acquire a 50% interest in the Carson Lake Project, providing a minimum of 30 MW of renewable energy (from a nominal net 24 MW to 40 MW) under the terms of a Joint Operating Agreement with an affiliate of Ormat Technologies Inc.

·	Approval to construct the 6 MW Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Gas Pipeline.

Approval of various electric transmission projects at a total estimated cost of $220 million. The majority of which is the Sunrise 500 kV Tap project with a scheduled commercial operation date of 2011 and a total estimated cost of $182 million (not including previously purchased land and land rights).

However, as a result of the potential acquisition of the Bighorn Generating Facility announced in April 2008, NPC will be resubmitting its 7th amendment to its' IRP and filing an 8th amendment in the latter part of May 2008. The requested approval of Harry Allen and Sunrise 500 kV TAP projects and the update of the Ely Energy Center, which were originally in the 7th amendment, will now be included in the 8th amendment, along with a request to approve the acquisition of the Bighorn Generating Facility.

Sierra Pacific Power Company

SPPC Nevada 2007 General Rate Case

In December 2007, SPPC filed its statutorily required electric general rate case ("GRC") utilizing the hybrid methodology that was authorized by the 2007 Nevada Legislature. The hybrid methodology incorporates historical costs and certain projected costs. Under this new methodology, the projected costs must be known and measurable and must begin prior to the rate effective date.

In its GRC, SPPC is requesting the following:

·	Increase in general rates by $110.8 million, approximately a 12.5% increase;

·	Return on equity (ROE) and rate of return (ROR) of 11.5% and 8.73%, respectively;

·	Authorization to recover the costs of major plant additions including the new Tracy 541 MW combined cycle generating plant and new transmission / distribution facilities; and

·	Authorization to recover the projected operating and maintenance costs associated with the new combined cycle generating plant.

Hearings began in April 2008 and will continue through early May with the new rates to be in effect on July 1, 2008.

SPPC Nevada Gas DEAA and BTER Update

In December 2007, SPPC filed for the authority to implement quarterly BTER adjustments for its natural gas and liquefied propane gas services. The authority was approved in January 2008, and as a result, in February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications SPPC requests to decrease rates by $9.9 million, a decrease of 5.53%, while refunding an over collection of $11.4 million in deferred natural gas and liquid propane costs. The new DEAA rate will be effective October 1, 2008 and the going forward BTER became effective April 1, 2008.

SPPC Nevada Electric DEAA and BTER Update

In February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications SPPC requests to decrease rates by $42.1 million, a decrease of 4.57%, while refunding an over collection of $20.9 million in deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2008 and the going forward BTER became effective April 1, 2008.

SPPC Nevada Electric Second Amendment to 2007 Integrated Resource Plan (IRP)

In March 2008, SPPC filed its second amendment to its 2007 IRP requesting approval to modify the schedule and development budget for the EEC in a manner consistent with the amendment to the NPC IRP described above, approval of a purchase power agreement, authority to fund CO2 research and approval of a revised load forecast. However, similar to NPC's resubmission of its 7th amendment discussed above, SPPC will also resubmit its 2nd amendment and file a 3rd amendment in the latter part of May 2008, which will address the update of the EEC that was originally in the 2nd amendment.

SPPC California Energy Cost Adjustment Clause

In April 2008, SPPC filed to decrease rates by $12.2 million, a decrease of 15.2%. The rates requested in this filing will be effective September 1, 2008.

Settled Rate Cases

NPC Fifth Amendment to 2006 Integrated Resource Plan (IRP)

In December 2007, NPC filed its fifth amendment to its 2006 IRP requesting approval of three items: 1) a revised Demand Side Management Plan; 2) a settlement agreement and new long-term power purchase agreement for approximately 50 MW of summer season capacity; and 3) a new long-term tolling agreement that will provide 570 MW of unit contingent summer season capacity. In March 2008, a stipulation between NPC and the intervening parties was accepted by the PUCN which recommended approval of the three items, as requested.

SPPC Nevada 2003 General Rate Case

In its 2003 GRC, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project. SPPC's participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable.

In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. As a result, these amounts were expensed in 2004. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). On January 25, 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). On March 27, 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. On June 12, 2006, the District Court granted the PUCN’s motion to stay the Order. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and on January 18, 2007 the matter was remitted back to the District Court, which, consistent with its January 25, 2006 order, remanded the matter back to the PUCN for further review.

On March 18, 2008, the PUCN issued an order to place $5.8 million (Nevada jurisdiction) of the previously disallowed $43 million unreimbursed costs in a regulatory asset account without a carrying charge. As a result of this order and in accordance with SFAS 90, Accounting for Abandonments and Disallowances of Plant Costs, SPPC recognized approximately $4.3 million in income for the three months ended March 31, 2008. The remaining difference of $1.5 million will be recognized over an approximate six year period. The time for any party to appeal the PUCN's decision ends in June 2008.

NOTE 4. LONG-TERM DEBT

As of March 31, 2008, NPC’s, SPPC’s and SPR’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):

	NPC			SPPC		SPR Holding Co. and Other Subs.		SPR Consolidated
2008	$	3,463		$	100,952	$	-	$	104,415
2009		22,218			600		-		22,818
2010		48,004			-		-		48,004
2011		369,924			-		-		369,924
2012		136,448			100,000		63,670		300,118
		580,057			201,552		63,670		845,279
Thereafter		2,005,750			973,250		460,539		3,439,539
		2,585,807			1,174,802		524,209		4,284,818
Unamortized Premium(Discount) Amount		(12,563	)		10,620		910		(1,033	)
Total	$	2,573,244		$	1,185,422	$	525,119	$	4,283,785

The preceding table includes obligations related to capital lease obligations.

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

NOTE 5. DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC and NPC apply SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (“SFAS 133”), as amended by SFAS 138, SFAS No. 149, SFAS No. 155, and SFAS No. 157. As amended, SFAS 133 establishes accounting and reporting standards for derivatives instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those 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. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and 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 purchase and normal sales are accounted for under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value.

Commodity Risk

The energy supply function encompasses the reliable and efficient operation of the Utilities’ generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. SPR’s and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

Adoption of SFAS 157

Effective January 1, 2008, SPR and the Utilities adopted SFAS 157, which defines fair value, establishes a framework for measuring fair value and enhances disclosures about assets and liabilities recorded at fair value.

SFAS 157 also establishes a three-level hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Derivative instruments used by SPR and the Utilities to manage energy price risk are valued using quoted exchange prices, external dealer prices and option pricing modules that utilize readily observable market parameters and are therefore classified within level 2 of the fair value hierarchy. The three levels are defined as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 – Unobservable inputs that are supported by little or no market activity and that are significant.

Determination of Fair Value

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps and options. Forwards and swaps are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Options are valued based on an income approach that uses an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option volatility rates. The determination of the fair value for its derivative instruments not only include counterparty risk, but also incorporate the impact of SPR and the Utilities nonperformance risk on its liabilities. Nonperformance risk is based on the credit quality of SPR and the Utilities and has minimal impact to the fair value of its derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of SPR, NPC and SPPC and the related regulatory assets/liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS 133. Due to deferred energy accounting treatment under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income (dollars in millions):

	March 31, 2008 Fair Value Level 2 (dollars in millions)						December 31, 2007 Fair Value (dollars in millions)
	SPR		NPC		SPPC		SPR			NPC			SPPC

Risk management assets- current	$	178.9	$	131.4	$	47.5	$	22.3		$	16.1		$	6.2
Risk management assets- noncurrent		15.9		11.7		4.2		12.5			9.1			3.4
Total risk management assets		194.8		143.1		51.7		34.8			25.2			9.6

Risk management liabilities- current		2.8		1.5		1.3		39.5			27.0			12.5
Risk management liabilities- noncurrent		4.3		3.5		0.8		7.4			5.1			2.3
Total risk management liabilities		7.1		5.0		2.1		46.9			32.1			14.8

Less prepaid electric and gas options		14.3		10.8		3.5		13.9			10.2			3.7

Risk management regulatory assets/liabilities – net(1)	$	173.4	$	127.3	$	46.1	$	(26.0	)	$	(17.1	)	$	(8.9	)

1 When amount is negative it represents a Risk Management Regulatory Asset (loss), when positive it represents a Risk Management Regulatory Liability (gain).

The primary factors that cause changes in the fair values are the number and size of the Utilities open derivative positions with its counterparties and the changes in forward commodity prices. As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities open derivative positions with its counterparties and the changes in forward commodity prices. The increase of risk management assets as of March 31, 2008, as compared to December 31, 2007, is mainly due to favorable open derivative positions on natural gas options held by the Utilities to hedge energy price risk for their customers resulting from higher commodity prices for natural gas at March 31, 2008 relative to contract prices.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Reid Gardner Station

Surface and Groundwater Matters

Reid Gardner Station is a coal generating station consisting of four units. Unit no. 4 is co-owned by the California Department of Water Resources (CDWR) 67.8% and 32.2% by NPC. NPC is the operating agent.

Reid Gardner has a number of raw water and scrubber make-up storage ponds as well as ponds used for process water evaporation and fly ash settling. Process water, which has been used beyond the treatable limits, is routed to onsite ponds for evaporation. Waste management units are present throughout the site and surrounding area. Environmental contaminants identified at Reid Gardner include but are not limited to, elevated concentrations of total dissolved solids, sulfate, chloride, dissolved metals, volatile organic compounds and petroleum hydrocarbons.

In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next ten years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan was reviewed and approved by NDEP. In collaboration with NDEP, NPC evaluated remediation requirements and in May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. The order specified that any future ponds will be double-lined with inter-liner leak detection in accordance with the NDEP Authorization to Discharge Permit issued October 2005. Pond construction and lining costs to satisfy the NDEP order expended through December 31, 2007 were approximately $45 million. Expenditures for 2008 are projected to be approximately $2.8 million which will fulfill the requirements of the order for a total expenditure of approximately $47.8 million.

Over the last two years, the water division of NDEP has been in discussions with NPC regarding what additional surface and groundwater cleanup may be required at the site, beyond the scope of the current pond relining project. The proposed solution was to enter into an Administrative Order on Consent (AOC) and the final form of the proposed AOC was delivered to NPC in December 2007. Until such time, NPC did not know the extent of the obligation or scope of work that would be required to effect site restoration due to the complexities associated with environmental remediation of the target media and the evolving standards of acceptable remediation standards. As a result, management was unable to reasonably estimate the cost of this comprehensive remediation project prior to concluding the negotiations and receiving the final AOC from the NDEP.

In February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. The AOC was designed to supersede previous agreements for remedial activities at the site and take a comprehensive approach to address historical environmental impacts associated with facility operations. As a result of the AOC, NPC has recorded as an asset retirement obligation of approximately $20 million, which it expects to receive regulatory recovery of, similar to other Asset Retirement Obligations. Other costs are expected to include capital expenditures and remediation costs of approximately $32.3 million and operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is initiated and additional characterization is completed.

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 or sale of the property.

Litigation Contingencies

Nevada Power Company

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station (Navajo Station) which is located in Northern Arizona and is operated by the Salt River Project (Salt River). Other participants in the Navajo 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 (Mohave 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.

Royalty Claim

On October 15, 2004, Navajo Station’s coal supplier, Peabody Western Coal Co. (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 Station, Salt River, is defending the suit on behalf of the Navajo Joint Owners. NPC believes Peabody WC’s claims are without merit and intends to contest them. At this time, discovery is ongoing. In October, 2007, the Navajo Joint Owners filed a motion for partial summary judgment against Peabody WC’s claims for reimbursement of attorney fees and indemnification of liability arising out of the DC Lawsuit. In January 2008, Peabody filed responses to the Navajo Joint Owner’s motion. On February 13, 2008, the Navajo Joint Owners filed a second partial summary judgment motion seeking dismissal of another count raised by Peabody concerning indemnity arising out of the DC Lawsuit. The court has yet to rule on both partial summary judgment motions. The case is set for trial in December, 2008. NPC is unable to predict the outcome of this matter or whether any other liability may arise as a result of 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 Station and the Mohave 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 Navajo Station and the Mohave Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 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 court dismissed all claims against Salt River. The action had been stayed since October 5, 2004. In March, 2008, the US District Court lifted the stay and referred pending discovery related motions to a Magistrate judge.

Retiree Health Care and Reclamation Claims

In addition to the above action before the Missouri State Court, Peabody further asserted in 1994 that the Navajo Joint Owners are liable under the Coal Supply Agreement (CSA) for Retiree Health Care Costs (RHCC) and Final Reclamation Costs (FRC), which Peabody WC is obligated to pay after the CSA expires and the Kayenta Mine closes. In 1996, Salt River and the Navajo Joint Owners filed a complaint in the Maricopa County (Arizona) Supreme Court seeking determinations that they are not liable for RHCC or FRC or, alternatively, that Peabody WC cannot recover RHCC and FRC until after the CSA ends. The case was dormant for several years, while Peabody WC pursued other RHCC and FRC claims arising out of similar coal contracts. The RHCC matter is in the early stages of litigation. The FRC claim went to arbitration and parties are in the early process of selecting a panel. Settlement discussions, led by Salt River, are continuous and ongoing. NPC is briefed periodically by Salt River as settlement discussions advance. NPC cannot predict the final outcome of the settlement, but has recorded a $17.4 million liability which management has assessed as the approximate amount to be paid, and a corresponding other regulatory asset for such claims, as management believes that these costs are recoverable through deferred energy.

Nevada Power Company and Sierra Pacific Power Company

Calpine Settlement

On September 19, 2007, NPC, SPPC and Calpine Corporation (“Calpine”) entered into a settlement agreement (the “Settlement Agreement”) that resolved the issues and claims pertaining to three proofs of claim (Claim Nos. 5177, 5178 and 5179) filed by the Utilities against Calpine in Calpine’s bankruptcy proceeding. The Settlement Agreement was approved by the United States Bankruptcy Court for the Southern District of New York on October 10, 2007, and by the Federal Energy Regulatory Commission (“FERC”) on December 28, 2007, in orders that are final and non-appealable.

Claim Nos. 5177 and 5179 filed by SPPC and NPC relate to complaints filed with FERC in December 2001 under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in reaction to the Western United States energy crisis. The Settlement Agreement provided that, for Claim Nos. 5177 and 5179, SPPC and NPC would receive general unsecured claims in the Calpine bankruptcy proceeding of approximately $1.7 million and $1.3 million respectively, totaling $3 million. In February 2008, Calpine distributed shares of Calpine common stock to SPPC and NPC with respect to Claim No. 5177 and 5179, at the approximate value at the time of the distribution of approximately $1.3 million, and $1.1 million, respectively. The Utilities recognized these amounts as income for the three months ended March 31, 2008.

Claim No. 5178 filed by NPC regarding Calpine’s alleged breach of a 400 MW transmission service agreement (“TSA”) and a 2002 settlement agreement approved by the FERC. The Settlement Agreement provided that the claim shall be amended to reflect a general unsecured claim of $18 million against Calpine. NPC agreed to treat the distribution in respect to Claim No. 5178 as a prepayment for a new 400 MW TSA (“New TSA”) with a term commencing January 1, 2008 and ending approximately March 31, 2010, assuming no change in NPC’s open access transmission tariff (“OATT”) service schedules and, in the event of any such changes, ending on the date the $18 million is depleted based on the applicable OATT service rate schedule. In February 2008, Calpine distributed shares of Calpine common stock to NPC having an approximate value at that time of $14.4 million, which will be recognized as transmission revenue over the term of the new TSA.

The distributions discussed above represent approximately 80% of the balance owed to NPC and SPPC under the three proofs of claims filed. Management cannot predict if the remaining 20% will be recovered due to the status of Calpine’s bankruptcy proceedings, and as such has not recorded any further amounts as income. Subsequent to the distribution, NPC and SPPC sold all of their shares of Calpine common stock and recorded a gain of $1.8 million for the three months ended March 31, 2008.

Sierra Pacific Power Company

Farad Dam

SPPC owns four hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (Insurers) for the flume and dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs. In May 2005, Insurers filed a motion for summary judgment on the coverage issue, which has been denied. In October 2005, Insurers filed another partial summary judgment motion with respect to coverage, which the court also denied. On June 16, 2006, Insurers filed new summary judgment motions, which SPPC opposed. The Court denied the motions and asked parties to brief the Court on certain insurance coverage issues involving timing and cost recovery associated with rebuilding the dam. The case went to trial in April 2008. The Court asked the parties to file post-trial briefs in May 2008 and a decision is expected in the summer of 2008. Management has not recorded a loss contingency for this matter, as the loss, if any, cannot be estimated at this time.

Other Legal Matters

SPR 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.

NOTE 7. EARNINGS PER SHARE (EPS) (SPR)

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.

The following table outlines the calculation for earnings per share (EPS):

		Three months ended March 31,
		2008		2007
Basic EPS
Numerator ($000)
	Net income applicable to common stock	$	24,058	$	15,607

Denominator
	Weighted average number of common shares outstanding		233,836,234		221,245,427

Per Share Amounts
	Net income applicable to common stock	$	0.10	$	0.07

Diluted EPS
Numerator ($000)
	Net income applicable to common stock	$	24,058	$	15,607

Denominator (1)
	Weighted average number of shares outstanding before dilution		233,836,234		221,245,427
	Stock options		60,750		151,856
	Non-Employee Director stock plan		56,313		40,665
	Employee stock purchase plan		-		3,143
	Restricted Shares		1,311		-
	Performance Shares		367,364		260,763
			234,321,972		221,701,854

Per Share Amounts
	Net income applicable to common stock	$	0.10	$	0.07

(1)

The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan for the three months ended March 31, 2008 and 2007, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the three months ended March 31, 2008 and 2007, 909,795 and 874,823 shares, respectively, would be included.

NOTE 8. PENSION AND OTHER POSTRETIREMENT BENEFITS NOTE

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 September 30 measurement date (dollars in thousands):


Sierra Pacific Resources, consolidated
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	6,022		$	5,725		$	565		$	768
Interest cost		10,790			9,855			2,218			2,570
Expected return on plan assets		(12,661	)		(10,474	)		(2,032	)		(1,309	)
Amortization of prior service cost		408			407			(748	)		31
Amortization of Transition Obligation		-			-			-			242
Amortization of net (gain)/loss		772			1,803			890			815
Settlement (gain)/loss		-			-			-			-

Net periodic benefit cost	$	5,331		$	7,316		$	893		$	3,117


Nevada Power Company
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	3,550		$	3,273		$	295		$	260
Interest cost		5,353			4,744			555			543
Expected return on plan assets		(6,067	)		(4,750	)		(680	)		(310	)
Amortization of prior service cost		363			358			179			30
Amortization of Transition Obligation		-			-			-			242
Amortization of net (gain)/loss		375			857			218			171
Settlement (gain)/loss		-			-			-			-

Net periodic benefit cost	$	3,574		$	4,482		$	567		$	936


Sierra Pacific Power Company
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	2,178		$	2,138		$	253		$	494
Interest cost		5,086			4,775			1,626			2,010
Expected return on plan assets		(6,265	)		(5,492	)		(1,317	)		(968	)
Amortization of prior service cost		52			53			(931	)		-
Amortization of Transition Obligation		-			-			-			-
Amortization of net (gain)/loss		336			867			657			639
Settlement (gain)/loss		-			-			-			-

Net periodic benefit cost	$	1,387		$	2,341		$	288		$	2,175

SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” (SFAS 158) requires companies to eliminate the early measurement date and to measure their Defined Benefit Pension and Other Postretirement Plans consistent with their fiscal year end. SFAS 158 provided a transition alternative to the elimination of the early measurement date by allowing earlier measurements determined for year end reporting of the fiscal year immediately preceding the year that the measurement date provisions are applied to be used to calculate the additional expense. As such and in accordance with SFAS 158, the amounts below represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007. SPR, NPC and SPPC recorded additional pension and other postretirement benefits costs relating to the elimination of the early measurement date to beginning retained earnings, of $5.3 million and $1.0 million; $3.6 million and $0.6 million; and $1.4 million and $0.4 million, respectively, before taxes.

As previously disclosed in Note 11, Retirement Plan and Post-retirement Benefits, in the 2007 Form 10-K, expected contributions for 2008 are $1.9 million for the pension plan and $0.4 million for other postretirement benefits. Management will continue to re-assess the amounts to be funded for each of the plans in 2008, after final funding rules are adopted by the Internal Revenue Service.

NOTE 9. DIVIDENDS

On February 7, 2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share which was paid on March 12, 2008, to common shareholders of record on February 22, 2008. On April 28, 2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share, to common shareholders of record on May 23, 2008, payable on June 11, 2008.

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 Sierra Pacific Resources (SPR), Nevada Power Company (NPC), or Sierra Pacific Power Company (SPPC) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)	changes in environmental laws or regulations, including the imposition of limits on emissions of carbon dioxide from electric generating facilities, which could significantly affect our existing operations as well as on our construction program, especially the proposed Ely Energy Center;

(2)

construction risks, such as delays in permitting, changes in environmental laws, difficulty in securing adequate skilled labor, cost and availability of materials and equipment (including escalating costs for materials, labor and environmental compliance due to timing delays and other economic factors), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(3)	whether the Utilities can procure sufficient renewable energy sources in each compliance year to satisfy the Nevada Portfolio Standard;

(4)	changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, including the effect of weaker housing markets;

(5)

unseasonable weather, drought and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability to procure adequate supplies of fuel or purchased power and the cost of procuring such supplies, and could affect the amount of water available for electric generating plants in the Southwestern United States;

(6)

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 (for example, due to unseasonably hot weather), sharp increases in the prices for fuel, including increases in the price of coal and in the long term transportation costs for natural gas, and/or power or a ratings downgrade;

(7)

the ability and terms upon which SPR, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of unfavorable rulings by the Public Utilities Commission of Nevada (PUCN), untimely regulatory approval for such financings, and/or a downgrade of the current debt ratings of SPR, NPC, or SPPC;

(8)

financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability of capital, or interest rate fluctuations resulting from, among other things, the credit quality of bond insurers that guarantee certain series of the Utilities’ auction rate tax-exempt securities;

(9)	future economic conditions, including inflation rates and monetary policy;

(10)

unfavorable or untimely rulings in rate cases filed or to be filed by the Utilities with the PUCN, including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas costs recorded by SPPC for its gas distribution business;

(11)	wholesale market conditions, including availability of power on the spot market, which affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

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

(13)	the expiration of the appeal period relating to the proceedings to reverse the PUCN’s 2004 decision on SPPC’s 2003 General Rate Case (GRC), which disallowed the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project;

(14)	employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages;

(15)	changes in tax or accounting matters or other laws and regulations to which SPR or the Utilities are subject;

(16)	the effect of existing or future Nevada, California or federal legislation or regulations affecting electric industry restructuring, including laws or regulations which could allow additional customers to choose new electricity suppliers or change the conditions under which they may do so;

(17)

changes in the business or power demands of the Utilities’ major customers, including those engaged in gold mining or gaming, which may result in changes in the demand for services of the Utilities, including the effect on the Nevada gaming industry of the opening of additional Indian gaming establishments in California and other states; and

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

Other factors and assumptions not identified above may also have been involved in deriving these 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. SPR, 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.

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 Sierra Pacific Resources (SPR) and its two primary subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC), collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to SPR (holding company) and the Utilities collectively), and includes the following:

•

Results of Operations

•

Analysis of Cash Flows

	•	Liquidity and Capital Resources
	•	Energy Supply (Utilities)
	•	Regulatory Proceedings (Utilities)

SPR’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 segment operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of SPR and account for substantially all of SPR’s assets and revenues. SPR, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (SPR, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

SPR recognized net income applicable to common stock of $24.1 million for the three months ended March 31, 2008 compared to $15.6 million for the same period in 2007. Earnings increased primarily due to an increase in NPC’s Base Tariff General Rates (BTGR), as a result of NPC’s 2006 GRC, effective June 1, 2007, an increase to allowance for funds used during construction, the settlement with Calpine and reinstatement of previously disallowed costs related to Piñon Pine. In addition, earnings for the three months ended March 31, 2007 were increased approximately $7.2 million (net of taxes) by the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case, see Note 3, Regulatory Actions in the Notes to Financial Statements in the 2007 Form 10-K.

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 by the Utilities’ customers due to varying weather and other energy usage patterns necessitate 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 recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2008 and Beyond Outlook

In the Western and Southwestern portions of the United States, energy needs continue to increase; however, the development of generating facilities by utility companies has decreased. As a result, the cost of energy and natural gas continues to rise with increased demand and the decline in the ability to meet those demands. The economics of this situation coupled with variations in weather, the capabilities and limits on the Utilities, owned generating facilities, transmission constraints, regulations, and changes and potential changes in environmental law are a significant business issue for the Utilities. As a result, the Utilities’ strategies, as evidenced by their most recent amendments to their Integrated Resource Plans (IRP), are aimed at reducing dependence on purchased power by the use of energy efficiency and conservation programs and diversifying fuel mix, including renewable energy and owning more generating facilities.

2008 Key Objectives

·	Management of Energy Resources

o	Energy Efficiency and Conservation Programs

o	Purchase and Development of Renewable Energy Projects

o	Construction of Generating Facilities

o	Management of Energy Risk, including fuel and purchased power costs

·	Management of Environmental Matters

·	Management of Regulatory Filings

·	Further Broaden Access to Capital

Management of Energy Resources

Energy Management encompasses energy efficiency and conservation programs, diversification of fuel mix, optimization of generation assets, management of energy risk which includes the purchase of short term and long term supply contracts, transmission, storage, reliability and efficiency, and regulatory and legal considerations. The ability to balance and optimize these functions is a significant business challenge that we face.

Energy Efficiency and Conservation Programs

A part of our strategy to reduce dependence on purchased power is to manage our resources against our load requirements with energy efficiency and conservation programs. As part of the Clinton Global Initiative, the Utilities’ have committed to spending approximately $135 million over the next three years towards increasing efficiency and qualified conservation programs. NPC and SPPC have received PUCN approval of approximately $110.5 million and $29.8 million, respectively for the years 2008- 2010, which will be deferred as a regulatory asset subject to prudency review by the PUCN. The PUCN approval of the demand-side management (“DSM”) budget increase was a key step in expanding the energy savings yield from the DSM programs.

NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public, and low income). After the DSM percentage allowance is fully utilized, NPC’s and SPPC’s strategy is to continue to implement cost-effective DSM programs.

Furthermore, the Portfolio Standard, discussed below, allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. A portfolio energy credit is created for each kWh of energy conserved by qualified energy efficiency programs. Energy saved during peak demand hours earns double the portfolio energy credits. In April 2008, the Utilities filed their Portfolio Standard Annual Report for Compliance Year 2007 (the “Portfolio Report”). In the Portfolio Report, the Utilities reported that through energy efficiency measures they achieved 60% of the allowable 25% that may be used to meet the Portfolio Standard. In addition, NPC reported that it is in a position to achieve the maximum 25% in 2008.

Purchase and Development of Renewable Energy Projects

The Utilities have embarked on a strategy to invest in renewable energy that, along with purchased power contracts and an increase in DSM programs, will enhance the opportunity for the Utilities to fully meet the renewable energy portfolio standard (Portfolio Standard) as required by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewable energy resources. NPC’s current capital budget includes investing approximately $457 million for renewable energy projects through 2012.

Nevada law sets forth the Portfolio Standard, requiring providers of electric service to acquire, generate, or save a specific percentage of its total retail energy sales from renewable energy resources (Renewables). Renewables include biomass, geothermal, solar, waterpower and wind projects. In 2008, the Utilities are required to obtain 9% of their total energy from Renewables. The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015. Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources.

Nevada law requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In the Utilities’ April 2008 Portfolio Standard Annual Report for Compliance Year 2007 (submitted to the PUCN jointly), NPC reported that with PUCN approval of a sale and purchase of SPPC’s excess non-solar PCs, NPC met the non-solar Portfolio Standard. SPPC reported compliance with the non-solar component of the Portfolio Standard. However, due to the late commercial operation of planned solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard. Additionally, the report described the Utilities ongoing activities to reach full compliance with the Portfolio Standard in the near future.

In March 2008, NPC filed its 7th amendment to its’ 2007-2026 Integrated Resource Plan with the PUCN (“2006 Resource Plan”). Included in the amendment are renewable energy requests which seek approvals to acquire a 50% interest in a minimum 30 MW geothermal project (“Carson Lake Project”) and to construct a 6 MW Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Pipeline. Both projects are scheduled for commercial operation in late 2010, if approval is obtained by the PUCN.

Construction of Generating Facilities

Ely Energy Center

Included in the PUCN’s approval of the IRP is Phase 1 of the construction of the Ely Energy Center that consists of two 750 MW coal generation units to be located near Ely, Nevada. In addition to the generation units, the PUCN approved the development and construction of a 250-mile 500 kilovolt (kV) transmission line that would deliver electricity from the Ely Energy Center and from any possible future renewable resource projects in the area, as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state. The PUCN approved spending up to $300 million for development activities associated with the Ely Energy Center and transmission line; however, the PUCN placed a $155 million spending limit until the appropriate permits, as discussed below, are obtained. For planning purposes, it is currently assumed that the capacity of the project, as well as the development and construction costs, would be shared by NPC and SPPC on an 80% - 20% basis, respectively. The PUCN established the project as a “critical facility,” thereby allowing it to qualify for incentives that will be determined in a later filing. The total project costs are estimated to be approximately $5.0 billion if construction were to begin at the time of this filing. However, upon management's review on the timing of siting approvals, construction is not likely to begin before 2010. Depending on the timing of construction, negotiation of certain contracts, the potential initiation of any litigation challenging the project, and the timing and terms of permitting, among other factors, actual costs, scope, and timing of the completion of the project will likely differ materially from estimated costs.

In addition to PUCN approval and other factors, the timing and construction of the Ely Energy Center and transmission line are dependent on obtaining land use permits from the Bureau of Land Management and air permits from the Nevada Division of Environmental Protection (NDEP). On October 31, 2007, the NDEP published a notice of intent to issue a Class I air quality permit, together with a draft operating permit, with respect to the Ely Energy Center. The draft operating permit was subject to public comment, the comment period having ended on January 23, 2008. The NDEP will be responding to all public comments and upon completion of that task, the Utilities expect a final air quality permit to be issued. Possible changes to state and federal environmental laws or regulations, including those relating to carbon emissions from coal-fired power plants, could impact either permitting process and thereby affect the Utilities’ ability to proceed or could require design changes to the project overall. At this time we are unable to predict the timing or outcome of the permitting processes.

Additionally, due to concerns about the possible effect of carbon dioxide and other “greenhouse gases” on the environment, and particularly on climate change, there is considerable debate both at a local level and in Congress as to whether or not additional coal-fired generating stations should be built in the United States. Certain Congressional leaders, environmental advocacy groups and regulatory agencies have voiced objections to the construction of coal generating facilities in Nevada, including the Ely Energy Center. Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level which are aimed at the reduction of greenhouse gas emissions. While the Utilities believe that the Ely Energy Center represents the best alternative for meeting the increasing electricity requirements of the State of Nevada, the Utilities cannot predict the outcome of pending or future legislative and rulemaking proposals, their effect on the permitting requirements for the Ely Energy Center described above, or their effect otherwise on the project overall, including future PUCN review and approval. It is possible that the adoption of one or more such legislative or regulatory proposals could trigger a need to reevaluate the feasibility, economic and otherwise, of the Ely Energy Center as a coal generating facility or other aspects of the project overall.

If the Ely Energy Center is further delayed, or if the current planning assumptions for the project change materially, the Utilities would need to explore other sources of power for meeting the projected electricity demand in their service territories. The most likely alternative to coal generation would involve increased use of natural gas, either through increased use of natural gas fueled purchased power or the construction of additional Utility-owned natural gas generating facilities, or a combination of both. Such increased use of natural gas likely would further subject the Utilities and their customers to natural gas price volatility, as well as to any potential regional supply adequacy issues.

Natural Gas Generating Units

NPC has begun the construction of 619 MWs of natural gas-fired combustion turbine peaking units at Clark Station expected to be in service in 2008 at an approximate cost of $403.4 million. Additionally, in 2007, NPC began construction of a 500 MW natural gas generating station at the existing Harry Allen Station.

On April 22, 2008, NPC announced its intention to purchase the 598 MW (nominally rated), natural gas fired combined cycle power plant, Bighorn Generating Station, from Reliant Resources, Inc., for approximately $500 million. NPC expects the final acquisition to occur later in 2008 following required reviews and approvals from various regulatory authorities. As a result of the potential acquisition of the Bighorn Generating Facility, NPC will be re-submitting its 7th amendment to its' IRP as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements and filing an 8th amendment in the latter part of May 2008. The requested approval of the Harry Allen and Sunrise 500 kV TAP projects and the update of the Ely Energy Center, which were originally in the 7th amendment, will now be included in the 8th amendment along with a request to approve the acquisition of the Bighorn Generating Facility. Additionally, SPPC will be re-submitting its 2nd amendment to its’ IRP, as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements and filing a 3rd amendment in the latter part of May 2008, which will address the update of the Ely Energy Center that was originally in the 2nd amendment.

SPPC continues to construct a 541 MW gas fired high efficiency combined cycle generator at the Tracy Plant. SPPC anticipates an in-service date of mid 2008.

Management of Energy Risk

Entering 2008, the Utilities expect to have open positions resulting from the management of their portfolio of generation resources, load obligations, and purchased power and fuel contracts, due to unfolding developments in regional energy markets. The risks associated with the open positions are addressed in various ways. The Utilities implement a prudent strategy of piecemeal procurements transacted in regular intervals and completed before the start of the peak summer season. This provides the Utilities with ample opportunities for optimizing their portfolio on a rolling basis in anticipation of changes in system conditions, load forecasts, and regional energy market fundamentals. The Utilities also coordinate the planned maintenance schedules of their owned generating plants and transmission facilities with expectations of start dates of new generating plants or purchased power contracts.

Management of Environmental Matters

The impact environmental laws can have on existing generating facilities and current and prospective capital construction projects include but are not limited to increased costs, closure of existing facilities, mandated equipment upgrades, and termination of the construction of facilities. Environmental laws already affect the energy we buy as discussed above under Purchase and Development of Renewable Energy Projects. In the next five years, NPC is projected to spend $214.3 million on certain major environmental projects/upgrades. Additionally, as discussed above, under Construction of Generating Facilities, Ely Energy Center, environmental laws will play a significant role in the construction of Ely Energy Center.

A key objective for the Utilities in 2008 will be to enhance and maintain our energy infrastructure investments in ways that meet customer demand for reliable energy in an efficient and environmentally responsible manner. The Utilities believe that a diverse and balanced portfolio of energy resources represents opportunity for reliability and cost control, yet are also mindful of our overriding environmental responsibility. The Utilities are committed to making technology choices with a primary focus on limiting emissions and optimizing our investments so that prices remain competitive. To meet the growing demand for power, the Utilities are investing in a new generation of highly efficient and environmentally advanced power plants, both coal and natural gas fired as well as adding new environmental controls to their existing plants. To help manage load demand, the Utilities are also increasing their participation and development of new energy efficiency and demand side conservation programs.

Management of Regulatory Filings

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for quarterly rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every three years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. Furthermore, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement. 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. Major projects included in the Utilities’ IRPs include the Ely Energy Center, Tracy Generating Station, and Clark Station. The Utilities incur costs for such items as deferred fuel and purchased power costs, operations and maintenance and capital projects; however, costs are not recovered through rates until approved by regulators, the timing between costs incurred and recovery is considered regulatory lag. As such, timely and accurate filings of these various rate cases is essential to the Utilities’ operating and financial performance as it reduces regulatory lag, which has a direct effect on the cash flows of the Utilities. Furthermore, the timing of the filings/decisions can affect the timing of construction and thus the economic benefits. As a result, the Utilities file quarterly BTER updates to minimize exposure to changes in fuel and purchased power expense, file amendments to IRP’s as changes in resource needs occur, and may use a “hybrid” test year for general rate filings as was the case with SPPC’s 2007 GRC which allows projected costs that are known and measurable to be included in rates so long as the expense has begun to be incurred prior to the rate effective date. The “hybrid” test year helps to reduce regulatory lag between rate case filings, particularly in the case of major construction projects and related operating and maintenance expense, where significant amounts of capital are required.

Significant decisions or filings expected in 2008 include, but are not limited to, a decision in SPPC’s 2007 GRC, amendments to the Utilities’ IRPs, and the filing of NPC’s GRC in late 2008.

Further Broaden Access to Capital

A significant focus in 2008 will again be to generate sufficient cash from operations to meet their operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs. However, significant amounts of capital may be necessary to fund existing and prospective construction projects, as well as volatile energy costs. The Utilities’ estimated cash requirement for 2008 is $1.2 billion and $7.6 billion over the next five years for capital projects, some of which include: the Ely Energy Center for $2.4 billion (does not include costs beyond 2012), Tracy for $43.6 million, Clark Station for $131.3 million, Harry Allen for $681.9 million, renewable development of $457 million and environmental upgrades of $214.3 million. Of these major projects approximately $930 million has been approved by the PUCN. In addition, pending regulatory approval of the Bighorn Generating Station, cash requirements for 2008 will increase by approximately $500 million. Management may be required to meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and if necessary, the issuance of equity by SPR. If energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, the Utilities may need to issue additional debt to support their operating costs or delay capital expenditures.

SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Consolidated)

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $10.4 million and $10.9 million of interest costs for the three months ended March 31, 2008 and 2007 respectively.

During the three months ended March 31, 2008, SPR recognized net income applicable to common stock of approximately $24.1 million compared to $15.6 million to the same period in 2007. The increase was primarily due to an increase in operating income, an increase in AFUDC and Allowance for Borrowed Funds Used During Construction, as a result of the construction of the Clark Peaking Units and the Tracy Expansion, reinstatement of disallowed plant costs related to Piñon Pine, as discussed further in Note 5, Commitments and Contingencies of the Condensed Notes to Financial Statements.

As of March 31, 2008 NPC had paid $24.9 million in dividends to SPR and SPPC had paid $13.3 million in dividends to SPR. On April 28, 2008, SPPC declared an additional $50 million dividend, which was paid on April 30, 2008.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the three months ended March 31, 2008 compared to the same period in 2007 due to a decrease in cash from financing activities partially offset by an increase in cash from operating activities and a decrease in cash used by investing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to NPC’s GRC, the Western Energy Crisis rate case, NPC’s 2001 Deferred Energy rate case, an increase in collections of accounts receivable balances, and an over-collection of revenues for gas and energy costs for NPC and SPPC. Partially offsetting these increases were expenditures for conservation programs, site studies and other regulatory activities in 2008, a reduction in deposits from transmission customers in 2008, the timing of 2007 interest payments due to debt redemption and refinancing in 2006, and lower accounts payable balances for energy and other suppliers in 2008.

Cash Used By Investing Activities. Cash used by investing activities decreased primarily due to the closing stages of major construction activity for the peaking units at Clark Station and the combined cycle natural gas power plant at the Tracy Generating Station which began in 2007 and 2006, respectively.

Cash From Financing Activities. Cash from financing activities decreased due to reduced borrowings through the Utilities’ long term credit facility and dividend payments to SPR shareholders in 2008.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Overall Liquidity

SPR’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 natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of March 31, 2008 (in millions)
	SPR		NPC		SPPC
Cash and Cash Equivalents	$	14.2	$	51.1	$	55.1
Balance available on Revolving Credit Facility		N/A	$	554.9	$	330.5
	$	14.2	$	606.0	$	385.6

In addition to cash on hand and the Utilities’ revolving credit facilities, the Utilities may issue debt up to $1.2 billion on a consolidated basis, subject to certain limitations discussed below and in the Utilities’ respective sections, to meet its financial obligations.

SPR and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities. To manage liquidity needs as a result of seasonal peaks in fuel requirement, SPR and the Utilities may use hedging activities. However, to fund long-term capital requirements, SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR from the issuance of equity by SPR.

SPR has approximately $40.7 million payable of debt service obligations for 2008, of which $17.9 million was paid in the first quarter 2008. SPR intends to pay the remaining interest payments through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below).

During the three months ended March 31, 2008, there were no material changes to contractual obligations as set forth in SPR’s 2007 Form 10-K for SPR. See NPC’s and SPPC’s respective sections for changes in contractual obligations.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of March 31, 2008, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $210.5 million of its unsecured 6.75% Senior Notes due 2017; and $250 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, SPR’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, SPR’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, 2008, SPR, NPC, SPPC and their subsidiaries had approximately $4.2 billion of debt and other obligations outstanding, consisting of approximately $2.6 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $524 million of debt at the holding company and other subsidiaries. Although SPR and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, SPR and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. 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. 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 currently pay dividends to SPR out of earnings and are therefore not affected by this provision. Moreover, 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 earnings, or in the absence of earnings, from other/additional paid-in capital accounts. If, however, the Utilities experienced a material loss and/or the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

As of March 31, 2008, NPC and SPPC were able to pay dividends of $814 million and $256 million, respectively, under the most restrictive test in its financing agreements. Management does not believe the total amount of dividends that the Utilities can pay to SPR under their financing agreements is significantly restrictive. In the first quarter of 2008, NPC and SPPC paid dividends to SPR of $24.9 million and $13.3 million, respectively. On April 28, 2008, SPPC declared a $50 million dividend to SPR, which was paid on April 30, 2008.

Credit Ratings

SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations (NRSRO’s): Dominion Bond Rating Service (DBRS), Fitch Ratings Ltd. (Fitch), Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s (S&P). As of April 29, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPR	Sr. Unsecured Debt	BB (low)	BB-	Ba3	BB-
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BB+
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	BB
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BB+

* Ratings are investment grade

On March 19, 2008, S&P increased the rating on SPR’s senior unsecured debt to BB- from B+, and the rating of NPC’s senior unsecured debt to BB from B. Three of the four rating agencies currently rate the Utilities’ senior secured debt investment grade. Moody’s and DBRS’s rating outlook for SPR, NPC and SPPC is Stable. S&P’s and Fitch’s rating outlook for SPR, NPC and SPPC is Positive.

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, and each rating should be evaluated independently of any other rating.

Credit Ratings of Bond Insurers

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of the Utilities, Variable Rate Notes of approximately $556 million are periodically reset through auction processes. These securities are supported by bond insurance policies provided by either Ambac Financial Group, Inc. ("AMBAC"), Financial Guaranty Insurance Company ("FGIC"), or MBIA, Inc. (collectively, the “Insurers”), and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. The uncertainty with the Insurers' credit quality has had an impact on the Utilities’ interest costs for the first quarter of 2008. With the ongoing review of the credit ratings of the Insurers, the Utilities are experiencing higher interest costs for these securities.

Financial Covenants

Nevada Power Company and Sierra Pacific Power Company

Each of NPC's $600 million Second Amended and Restated Revolving Credit Agreement and SPPC's $350 million Amended and Restated Revolving Credit Agreement, dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires that the Utility 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. The second requires that the Utility maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2008 both Utilities were in compliance with these covenants.

Ability to Issue Debt

Certain debt of SPR places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of March 31, 2008, SPR would be allowed to incur up to $1.2 billion of additional indebtedness on a consolidated basis.

Notwithstanding this restriction, under the terms of the debt, SPR would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the two Utilities’ integrated resource plans. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

If the applicable series of debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade by both Moody’s and S&P (see Credit Ratings above).

Nevada Power Company

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 the terms of certain SPR debt. As of March 31, 2008, NPC had approximately $1.6 billion of PUCN financing authority.

The financial covenants under NPC’s debt allow for greater borrowings than SPR’s cap on additional indebtedness; therefore, NPC is limited by SPR’s cap on additional indebtedness of $1.2 billion.

Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $1.2 billion, depending on the Utilities combined usage of their revolving credit facilities at the time of the covenant calculations.

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 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 NPC’s General and Refunding Mortgage Indenture (“Indenture”).

As of March 31, 2008, $2.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $799 million of General and Refunding Mortgage Securities as of March 31, 2008.

NPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of securities issuable under that indenture. See the 2007 Form 10-K for additional information.

Sierra Pacific Power Company

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 the terms of certain SPR debt. As of March 31, 2008, SPPC had approximately $745 million of PUCN financing authority.

The financial covenants under SPPC’s debt allow for lower borrowings than SPR’s cap on additional indebtedness; therefore, SPPC is not limited by SPR’s cap on additional indebtedness of $1.2 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 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 NPC’s General and Refunding Mortgage Indenture (“Indenture”).

As of March 31, 2008, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $369 million of General and Refunding Mortgage Securities as of March 31, 2008.

SPPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of securities issuable under that indenture. See the 2007 Form 10-K for additional information.

Cross Default Provisions

None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by SPR or the other Utility under any of their respective financing agreements. Certain of SPR’s financing agreements, however, do contain cross-default provisions that would result in event of default by SPR upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of SPR 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 SPR or the Utilities may rectify or correct the situation before it becomes an event of default.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $8.0 million during the three months ended March 31, 2008 compared to net income of $4.6 million for the same period in 2007.

As of March 31, 2008 NPC had paid $24.9 million in dividends to SPR. On May 1, 2008, SPR contributed capital to NPC of $30.0 million.

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 fuel and purchased power costs, provides a measure of income available to support the other operating expenses of NPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended March 31,
	2008		Change from Prior Year			2007
	2008		Change from Prior Year			2007
Operating Revenues:
Electric	$	469,172		12	%	$	418,165

Energy Costs:
Purchased power		93,750		-2	%		95,594
Fuel for power generation		164,021		0	%		164,085
Deferral of energy costs-net		45,775		70	%		26,932
	$	303,546		6	%	$	286,611

Gross Margin	$	165,626		26	%	$	131,554

Gross margin increased in the first quarter of 2008 compared to the same period in 2007 primarily due to an increase in Base Tariff General Rates (BTGR) as a result of NPC’s 2006 GRC, effective June 1, 2007. Also contributing to the increase was customer growth and an increase in transmission revenue.

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

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year
Electric Operating Revenues ($000):
Residential	$	205,378	$	179,249		14.6	%
Commercial		104,512		95,903		9.0	%
Industrial		133,013		124,826		6.6	%
Retail revenues		442,903		399,978		10.7	%
Other		26,269		18,187		44.4	%
Total Revenues	$	469,172	$	418,165		12.2	%

Retail sales in thousands
of megawatt-hours (MWH)		4,294		4,194		2.4	%

Average retail revenue per MWH	$	103.14	$	95.37		8.2	%

NPC’s retail revenues increased for the three months ended March 31, 2008 as compared to the same period in 2007 due to increases in retail rates and customer growth. Retail rates increased as a result of NPC’s various Base Tariff Energy Rate (BTER) and Deferred Energy Cases and NPC 2006 GRC, effective June 1, 2007 (see Note 3 Regulatory Actions of the Notes to the Financial Statements in the 2007 Form 10-K). Residential, commercial and industrial customers increased by 1.5%, 3.7% and 3.4%, respectively.

Electric Operating Revenues – Other increased for the three months ended March 31, 2008, compared to the same period in 2007. The increase is primarily due to the elimination of the reclassification of revenues associated with Mohave, as a result of NPC’s 2006 GRC, which in 2007 were reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on Mohave refer to Note 1, Summary of Significant Accounting Policies in the Notes to Financial Statements in the 2007 Form 10-K. Also contributing to the increase was transmission related revenue as a result of the Calpine settlement, as discussed further in Note 5, Commitments and Contingencies, and an increase in transmission revenue as a result of the completion of the Harry Allen to Mead transmission line.

Energy Costs

Energy Costs include Purchased Power and Fuel for Generation. 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 purchased power versus fuel for generation 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; and

·	Mandated power purchases

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year

Energy Costs	$	257,771	$	259,679		-0.7	%
Total System Demand		4,533		4,561		-0.6	%
Average cost per MWH	$	56.87	$	56.93		-0.1	%

Energy costs, total system demand and the average cost per MWh remained stable for the three months ended March 31, 2008 as compared to 2007. Slight variations in purchased power costs and fuel for power generation are discussed below.

Purchased Power

	Three Months Ended March 31,
	2008		2007		Change from Prior Year
Purchased Power	$	93,750	$	95,594		-1.9	%

Purchased Power in thousands
of MWhs		1,196		1,183		1.1	%
Average cost per MWh of
Purchased Power	$	78.39	$	80.81		-3.0	%

NPC’s purchased power costs and the average cost per MWh decreased slightly for the three months ended March 31, 2008 compared to the same period in 2007 primarily due to reductions in fixed capacity charges and a decrease in the cost of hedging instruments associated with purchased power.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year

Fuel for Power Generation	$	164,021	$	164,085		0.0	%

Thousands of MWhs generated		3,337		3,378		-1.2	%
Average cost per MWh of
Generated Power	$	49.15	$	48.58		1.2	%

The average cost per MWh of fuel for power generation average cost per MWh increased slightly for the three months ended March 31, 2008 as compared to the same time period in 2007. This was primarily due to higher natural gas prices which were partially offset by a decrease in costs for the settlements of hedging instruments.

Deferral of Energy Costs - Net

	Three Months Ended March 31,
	2008		2007		Change from Prior Year

Deferral of energy costs - net	$	45,775	$	26,932		70.0	%

Deferral of energy costs – net 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. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred. Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended March 31, 2008 and 2007 include amortization of deferred energy costs of $39.8 million and $24.1 million, respectively; and an over-collection of amounts recoverable in rates of $6 million in 2008 and $2.8 million in 2007.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended March 31,
	2008		2007		Change from Prior Year

Allowance for other funds used during construction	$	6,858	$	3,098		121. 4	%

Allowance for borrowed funds used during construction		5,355		2,550		110. 0	%
	$	12,213	$	5,648		116. 2	%

AFUDC increased for the three months ended March 31, 2008 compared to the same period in 2007 due to an increase in Construction Work-In-Progress (CWIP) associated with the construction of the Clark Peaking Units.

Other (Income) and Expenses

	Three Months Ended March 31,
	2008			2007			Change from Prior Year

Other operating expense	$	57,095		$	50,839			12.3	%
Maintenance expense	$	16,650		$	17,464			-4.7	%
Depreciation and amortization	$	40,630		$	35,761			13. 6	%
Interest charges on long-term debt	$	40,997		$	39,706			3.3	%
Interest charges-other	$	5,831		$	6,836			-14.7	%
Interest accrued on deferred energy	$	(1,794	)	$	(3,849	)		-53.4	%
Carrying charge for Lenzie	$	-		$	(10,082	)		N/A
Reinstated interest on deferred energy	$	-		$	(11,076	)		N/A
Other income	$	(5,747	)	$	(5,121	)		12.2	%
Other expense	$	1,361		$	2,042			-33.3	%

Other operating expense increased for the three months ended March 31, 2008, compared to the same period in 2007, primarily due to the reversal of a reserve established for Enron legal fees in 2007. In March 2007, the PUCN granted recovery of these expenses, see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2007 Form 10-K for further discussion. Also contributing to the increase in other operating expenses were increased costs for regulatory amortizations as compared to the same period in 2007, partially offset by lower legal fees.

Maintenance expense decreased for the three months ended March 31, 2008, compared to the same period in 2007, due to a decrease in maintenance costs for Lenzie and various items all of which were not individually significant, partially offset by increased maintenance costs for Reid Gardner and Silverhawk as a result of planned maintenance and forced outages.

Depreciation and amortization expenses increased during the three months ended March 31, 2008, compared to the same period in 2007, primarily as a result of depreciation expense related to Lenzie, beginning June 2007 as a result of NPC’s 2006 GRC.

Interest charges on long-term debt increased for the three months ended March 31, 2008, as compared to the same period in 2007, due primarily to higher interest rates on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2007 10-K for additional information regarding long-term debt.

Interest charges-other decreased for the three months ended March 31, 2008, as compared to the same period in 2007, due to lower interest associated with customer transmission deposits, offset by higher amortization of debt issuance costs, and interest expense related to new leases.

Interest accrued on deferred energy costs decreased for the three months ended March 31, 2008, as compared to the same period in 2007, due to lower deferred energy balances, partially offset by carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Carrying charges for Lenzie represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2007 Form 10-K for discussion of the accounting for the carrying charge for Lenzie.

Reinstated interest on deferred energy represents the carrying charges which were previously expensed as a result of the PUCN’s decision on NPC’s 2001 Deferred Energy Case. In March 2007, PUCN approved a settlement agreement allowing NPC to recover past carrying charges. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2007 Form 10-K.

Other income increased during the three months ended March 31, 2008, as compared to the same period in 2007, due to a gain from the settlement with Calpine, and the subsequent gain on sale of the stock received, as discussed further in Note 6, Commitments and Contingencies in the Condensed Notes to Financial Statements. This income was partially offset by lower interest income and the expiration of the amortization of gains associated with the disposition of property.

Other expense decreased during the three months ended March 31, 2008, as compared to the same period in 2007, due to several items, each of which is not materially significant.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the three months ended March 31, 2008 compared to the same period in 2007 due to a decrease in cash from operating and financing activities offset by a decrease in cash used by investing activities.

Cash From Operating Activities. The decrease in cash from operating activities was due primarily to an increase in expenditures for conservation programs, site studies and other regulatory activities in 2008, a reduction in deposits from transmission customers in 2008, and lower accounts payable balances for energy and other suppliers in 2008, offset partially by increases in rates in 2007 due to NPC’s GRC, the Western Energy Crisis Rate Case, NPC’s 2001 Deferred Energy rate case, and an over-collection of revenues for energy costs.

Cash Used By Investing Activities. Cash used by investing activities decreased primarily due to the closing stages of major construction activity for the peaking units at Clark Station, which began in 2007, and a reduction in construction for infrastructure.

Cash From Financing Activities. Cash from financing activities decreased due to a decrease in the issuance of debt, increased dividend payments in 2008 to SPR, partially offset by a $53 million investment by SPR.

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. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions.

Available Liquidity as of March 31, 2008 (in millions)
Cash and Cash Equivalents	$	51.1
Balance available on Revolving Credit Facility	$	554.9

	$	606.0

1 As of April 29, 2008, NPC had approximately $553.9 million available under its revolving credit facility.

In addition to cash on hand and the revolving credit facility, NPC may issue debt up to $1.2 billion on a consolidated basis, subject to certain limitations discussed below.

In January 2008, SPR contributed capital to NPC of approximately $53 million for general corporate purposes. In the first quarter of 2008, NPC paid dividends to SPR of $24.9 million. On May 1, 2008, SPR contributed capital to NPC of $30.0 million.

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facility. To manage liquidity needs as a result of seasonal peaks in fuel requirement, NPC may use hedging activities. However, to fund long-term capital requirements, as discussed below, NPC may meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facility and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the three months ended March 31, 2008, there were no material changes to contractual obligations as set forth in NPC’s 2007 Form 10-K. However, on April 21, 2008, NPC entered into a Purchase Agreement with Reliant Resources, Inc.. The Purchase Agreement is for a 598 MW (nominally rated), natural gas fired combined cycle facility, for approximately $500 million. The agreement is expected to be consummated by the end of 2008 pending various regulatory approvals.

Factors Affecting Liquidity

Financial Covenants

NPC's $600 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires that NPC 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. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2008, NPC was in compliance with these covenants.

Ability to Issue Debt

The financial covenants under NPC’s debt allow for greater borrowings than SPR’s cap on additional indebtedness; therefore, NPC is limited by SPR’s cap on additional indebtedness of $1.2 billion.

Ability to Issue General and Refunding Mortgage Securities

Credit Ratings

NPC is rated by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch, Moody’s and S&P. As of April 29, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BB+
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	BB

* Ratings are investment grade

On March 19, 2008, S&P increased the rating on NPC’s senior unsecured debt to BB from B. Three of the four rating agencies currently rate NPC’s senior secured debt investment grade. Moody’s and DBRS’s rating outlook for NPC is Stable. S&P’s and Fitch’s rating outlook for NPC is Positive.

Credit Ratings of Bond Insurers

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of NPC’s, Variable Rate Notes of approximately $207.5 million are periodically reset through auction processes. These securities are supported by bond insurance policies provided by either AMBAC or FGIC and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. The uncertainty with the Insurers' credit quality has had an impact on NPC’s interest costs for the first quarter of 2008. With the ongoing review of the credit ratings of the Insurers, NPC is experiencing higher interest costs for these securities.

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by SPR 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 $24.3 million for the three months ended March 31, 2008 compared to net income of $22.0 million for the same period in 2007.

As of March 31, 2008 SPPC had paid $13.3 million in dividends to SPR. On April 28, 2008, SPPC declared an additional $50 million dividend, which was paid on April 30, 2008.

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 fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended March 31,
	2008		Change from Prior Year			2007
Operating Revenues:
Electric	$	250,278		-1.0	%	$	252,879
Gas		85,594		0.6	%		85,120
	$	335,872		-0.6	%	$	337,999

Energy Costs:
Purchased power	$	90,106		8.2	%	$	83,310
Fuel for power generation		57,587		-10.1	%		64,069
Gas purchased for resale		66,896		-6.6	%		71,646
Deferral of energy costs-electric-net		8,507		-38.6	%		13,861
Deferral of energy costs-gas-net		2,203		13.3	%		1,945
	$	225,299		-4.1	%	$	234,831
Energy Costs by Segment:
Electric	$	156,200		-3.1	%	$	161,240
Gas		69,099		-0.9	%		69,701
	$	225,299		-2.4	%	$	230,941

Gross Margin by Segment:
Electric	$	94,078		2.7	%	$	91,639
Gas		16,495		7.0	%		15,419
	$	110,573		3.3	%	$	107,058

Gross margin increased for the first quarter of 2008 compared to the same period in 2007 primarily due to an increase in customer growth.

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,
	2008		2007		Change from Prior Year
Electric Operating Revenues:
Residential	$	89,879	$	88,009		2.1	%
Commercial		87,671		87,000		0.8	%
Industrial		65,782		70,441		-6.6	%
Retail revenues		243,332		245,450		-0.9	%
Other		6,946		7,429		-6.5	%
Total Revenues	$	250,278	$	252,879		-1.0	%

Retail sales in thousands
Mwh		2,151		2,150		0.0	%

Average retail revenues per Mwh	$	113.13	$	114.16		-0.9	%

SPPC’s retail revenues decreased for the three months ended March 31, 2008 as compared to the same period in the prior year primarily due to lower industrial energy revenues and MWh’s as a result of two large industrial customers moving to distribution-only service and standby service. Also contributing to the decrease were decreases in retail rates as a result of SPPC’s various energy and deferred energy rate cases. For details see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K. These decreases were partially offset by increased customer usage due to colder winter temperatures during 2008 compared to the same period in the prior year and the increase in the number of residential, commercial, and industrial customers (1.2%, 2.5%, and 0.7% respectively).

The decrease in Electric Operating Revenues – Other for the three month period ended March 31, 2008 compared to the same period in 2007 was primarily due to decreases in transmission revenue and rental income.

Gas Operating Revenues

	Three Months Ended March 31,
	2008		2007		Change from Prior year
Gas Operating Revenues:
Residential	$	50,747	$	47,712		6.4	%
Commercial		24,409		23,348		4.5	%
Industrial		7,987		7,299		9.4	%
Retail revenues		83,143		78,359		6.1	%
Wholesale		1,679		5,915		-71.6	%
Miscellaneous		772		846		-8.7	%
Total Revenues	$	85,594	$	85,120		0.6	%

Retail sales in thousands
of decatherms		6,782		6,288		7.9	%

Average retail revenues per decatherm	$	12.26	$	12.46		-1.6	%

SPPC’s retail gas revenues increased for the three months ended March 31, 2008 compared to the same period in 2007 primarily due to retail customer growth and colder temperatures in 2008. The number of residential, commercial, and industrial customers increased (1.5%, 3.1%, and 35.0%, respectively). These increases were partially offset by decreased retail rates as a result of SPPC’s 2007 and 2008 Natural Gas and Propane Deferred Rate Case and BTER updates. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K and Note 3, Regulatory Actions of the Condensed Notes to Financial Statements.

The wholesale revenues for the three months ended March 31, 2008, decreased compared to prior year 2007 primarily due to decreased availability of gas for wholesale sales.

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; and

·	Generation efficiency

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year

Energy Costs	$	147,692	$	147,379		0.2	%
Total System Demand		2,285		2,283		0.1	%
Average cost per MWH	$	64.64	$	64.55		0.1	%

Energy costs, total system demand and the average cost per MWh for the period ending March 31, 2008 remained relatively stable compared to the same period in 2007. Typically it is more economical for SPPC to purchase power than to generate in the first quarter of the year. However, in 2008 it was more economical for SPPC to rely first on its’ coal generating capacity than on purchased power or its other generating facilities.

Purchased Power

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year

Purchased Power:	$	90,106	$	83,310		8.2	%

Purchased Power in thousands of MWhs		1,293		1,330		-2.8	%

Average cost per MWh of Purchased Power	$	69.69	$	62.64		11.3	%

Purchased Power costs and the average cost per MWh increased for the three months ended March 31, 2008 as compared to the same period in 2007 primarily due to increases in natural gas prices which are reflected in the cost of purchased power.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year

Fuel for Power Generation	$	57,587	$	64,069		-10.1	%

Thousands of MWh generated		992		953		4.1	%
Average fuel cost per MWh
of Generated Power	$	58.05	$	67.23		-13.7	%

Fuel for power generation and average cost per MWh decreased for the three months ended March 31, 2008, as compared to the same period in 2007. The decrease was primarily due to lower costs associated with the settlement of hedging instruments partially offset by an increase in natural gas prices. In addition, fuel for generation costs decreased as a result of increased reliance on Valmy in 2008, which is a coal generating facility. The availability of Valmy in 2007 was limited due to outages. The cost of natural gas is significantly higher than the cost of coal. The volume of MWh generated increase due to a greater reliance on internal generation and cooler weather.

Gas Purchased for Resale

	Three Months Ended March 31,
					Change from
	2008		2007		Prior Year

Gas Purchased for Resale	$	66,896	$	71,646		-6.6	%

Gas Purchased for Resale
(in thousands of decatherms)		7,146		7,473		-4.4	%

Average cost per decatherm	$	9.36	$	9.59		-2.4	%

Gas purchased for resale and average cost per decatherm decreased for the three months ended March 31, 2008 as compared to the same period in 2007. The decrease is primarily due to lower volume and lower costs associated with the settlement of hedging instruments partially offset by an increase in natural gas prices. Volume decreased for the three months ended March 31, 2008 compared to the same period in 2007 primarily due to decreased availability of gas for wholesale sales.

Deferral of Energy Costs

	Three Months Ended March 31,
	2008		2007			Change from Prior Year

Deferral of energy costs – electric – net	$	8,507	$	13,861			-38.6	%
Deferral of energy costs - gas - net		2,203		(1,945	)		-213.3	%
Total	$	10,710	$	11,916

Deferral of energy costs – net 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. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Deferral of energy costs - electric – net for the three months ended March 31, 2008 and 2007 reflect amortization of deferred energy costs of $10 million and $12.1 million, respectively; and an under-collection of amounts recoverable in rates of $1.5 million in 2008 and an over-collection of $1.8 million in 2007.

Deferred energy costs - gas - net for the three months ended March 31, 2008 and 2007 reflect amortization of deferred energy costs of ($0.6) million, and $0.5 million, respectively; and an over-collection of amounts recoverable in rates in 2008 of $2.8 million and an under-collection of $2.4 million in 2007.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended March 31,
	2008		2007		Change from Prior Year

Allowance for other funds
used during construction	$	5,099	$	3,469		47. 0	%

Allowance for borrowed funds
used during construction		3,797		2,784		36. 4	%
	$	8,896	$	6,253		42. 3	%

AFUDC increased for the three months ended March 31, 2008 compared to the same period in 2007 due to an increase in Construction Work-In-Progress (CWIP) associated with the expansion of the Tracy Generating Station.

Other (Income) and Expense

	Three Months Ended March 31,
	2008			2007			Change from Prior Year

Other operating expense	$	33,505		$	32,848			2.0	%
Maintenance expense	$	6,472		$	6,281			3.0	%
Depreciation and amortization	$	21,440		$	20,472			4. 7	%
Interest charges on long-term debt	$	18,762		$	16,108			16.5	%
Interest charges-other	$	1,622		$	1,459			11.2	%
Interest accrued on deferred energy	$	558		$	(765	)		-172.9	%
Other income	$	(7,735	)	$	(1,831	)		322.4	%
Other expense	$	1,800		$	2,014			-10.6	%

Other operating expense increased slightly for the three months ended March 31, 2008 compared to the same period in 2007 primarily due to higher allocations of administrative and general costs to capital projects, partially offset by a reduction in accumulated provision for bad debt.

Maintenance expense increased slightly for the three months ended March 31, 2008 compared to the same period in 2007 mainly due to outages at Ft. Churchill during the first quarter of 2008 for turbine and steam line repairs.

Depreciation and amortization expenses increased for the three months ended March 31, 2008 compared to the same period in 2007 primarily as a result of increases to plant-in-service.

Interest charges on long-term debt for the three months ended March 31, 2008 increased from 2007 due primarily to issuing $325 million Series P notes in June 2007 and higher interest rates for variable rate debt in 2008, offset partially by the partial redemption of $221 million of the $320 million Series A note in June 2007. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2007 Form 10-K for additional information regarding long-term debt.

Interest charges-other for the three months ended March 31, 2008 increased compared to the same period in 2007 due to higher amortization costs related to new debt issues and redemptions in 2007.

Interest accrued on deferred energy costs decreased for the three months ended March 31, 2008 due to lower deferred energy balances compared to the same period in 2007. See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income increased during the three months ended March 31, 2008, when compared to the same period in 2007 primarily due to the reinstatement of previously disallowed costs associated with Piñon Pine, as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statement and the settlement with Calpine, as discussed further in Note 6, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Other expense decreased during the three months ended March 31, 2008, when compared to the same period in 2007, due to several items, each of which is not materially significant.

ANALYSIS OF CASH FLOWS

Cash flows increased during the three months ended March 31, 2008 compared to the same period in 2007 due to a decrease in cash used for investing activities, partially offset by a slight decrease in cash from operating activities and decrease in cash from financing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to the timing of 2007 interest payments due to debt redemption and refinancing in 2006 and regulatory expenditures in 2008. This decrease was partially offset by an increase in collections of accounts receivable balances compared to the same period in the prior year and an over-collection of revenues related to natural gas.

Cash Used By Investing Activities. Cash used by investing activities decreased primarily due to the closing stages of major construction activity at the Tracy Generating Station, which began in 2006.

Cash From Financing Activities. The decrease in cash from financing activities is due to a decrease in the issuance of debt and increased dividend payments to SPR partially offset by a $20 million investment by SPR.

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. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of March 31, 2008 (in millions)
Cash and Cash Equivalents	$	55.1
Balance available on Revolving Credit Facility(1)	$	330.5

	$	385.6

1 As of April 29, 2008, SPPC had approximately $311.2 million available under its revolving credit facility.

In addition to cash on hand and the revolving credit facility, SPPC may issue debt up to $1.2 billion on a consolidated basis, subject to certain limitations discussed below.

In January 2008, SPR contributed capital to SPPC of approximately $20 million for general corporate purposes. In the first quarter of 2008, SPPC paid dividends to SPR of $13.3 million. On April 28, 2008, SPPC declared a dividend to SPR for approximately $50 million, which was paid on April 30, 2008.

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facility. To manage liquidity needs as a result of seasonal peaks in fuel requirement, SPPC may use hedging activities. However, to fund long-term capital requirements, as discussed below, SPPC may meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facility and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the three months ended March 31, 2008, there were no material changes to contractual obligations as set forth in SPPC’s 2007 Form 10-K.

Factors Affecting Liquidity

Financial Covenants

SPPC's $350 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires that SPPC 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. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2008, SPPC was in compliance with these covenants.

Ability to Issue Debt

The financial covenants under SPPC’s debt allow for greater borrowings than SPR’s cap on additional indebtedness; therefore, SPPC is limited by SPR’s cap on additional indebtedness of $1.2 billion.

Ability to Issue General and Refunding Mortgage Securities

Credit Ratings

SPPC is rated by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch, Moody’s and S&P. As of April 29, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BB+

* Ratings are investment grade

Three of the four rating agencies currently rate SPPC’s senior secured debt investment grade. Moody’s and DBRS’s rating outlook for SPPC is Stable. S&P’s and Fitch’s rating outlook for SPPC is Positive.

Credit Ratings of Bond Insurers

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of SPPC’s, Variable Rate Notes of approximately $348.3 million are periodically reset through auction processes. These securities are supported by bond insurance policies provided by the Insurers and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. The uncertainty with the Insurers' credit quality has had an impact on SPPC’s interest costs for the first quarter of 2008. With the ongoing review of the credit ratings of the Insurers, SPPC is experiencing higher interest costs for these securities.

Cross Default Provisions

SPPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by SPPC upon an event of default by SPR or NPC under any of their respective financing agreements. 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.

REGULATORY PROCEEDINGS (UTILITIES)

SPR is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, SPR and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and CPUC. In addition, the PUCN, CPUC, or the FERC have the authority to review allocations of costs of non-power goods and administrative services among SPR and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between SPR, NPC and/or SPPC and/or any other affiliated company.

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the California Public Utilities Commission (CPUC) with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit Integrated Resource Plans (IRPs) to the PUCN for approval.

Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to 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 rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities are required to file annual electric and gas Deferred Energy Accounting Adjustment (DEAA) cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly Base Tariff Energy Rate (BTER) Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER Updates recover current energy costs. As of March 31, 2008, NPC’s and SPPC’s balance sheets included approximately $236.9 million and credit of $43.7 million, respectively, of deferred energy costs of which $286.3 million and $5.6 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

Rate case applications filed in 2007 and 2008, as well as other regulatory matters such as, the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2008, SPR, 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).

		Expected Maturity Date
									Fair
		2008	2009	2010	2011	2012	Thereafter	Total	Value
Long-term Debt
	SPR
	Fixed Rate	$ -	$ -	$ -	$ -	$ 63,670	$ 460,539	$ 524,209	$ 530,298
	Average Interest Rate	-	-	-	-	7.80%	7.77%	7.77%

	NPC
	Fixed Rate	$ 8	$ -	$ -	$ 364,000	$ 130,000	$ 1,786,579	$ 2,280,587	$ 2,297,926
	Average Interest Rate	8.17%	-	-	8.14%	6.50%	6.34%	6.64%
	Variable Rate	$ -	$ 15,000	$ 40,000	$ -	$ -	$ 192,500	$ 247,500	$ 247,500
	Average Interest Rate	-	5.63%	3.67%	-	-	5.82%	5.46%

	SPPC
	Fixed Rate	$ 100,952	$ 600	$ -	$ -	$ 100,000	$ 625,000	$ 826,552	$ 815,307
	Average Interest Rate	7.97%	6.40%	-	-	6.25%	6.39%	6.57%
	Variable Rate	$ -	$ -	$ -	$ -	$ -	$ 348,250	$ 348,250	$ 348,250
	Average Interest Rate	-	-	-	-	-	5.29%	5.29%

	Total Debt	$ 100,960	$ 15,600	$ 40,000	$ 364,000	$ 293,670	$ 3,412,868	$ 4,227,098	$ 4,239,281

Commodity Price Risk

See the 2007 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, 2007.

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 $187.9 million as of March 31, 2008, which increased from the $4.9 million balance at December 31, 2007 and the $62.0 million balance at March 31, 2007. The increase from December 31, 2007 is primarily an increase in prices of oil and natural gas during the first quarter of 2008.

ITEM 4 AND ITEM 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

SPR, 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, 2008, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the first quarter of 2008 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

As of the date of this report, there have been no material changes with regard to administrative and judicial proceedings involving regulatory, environmental and other matters as disclosed in SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2007, except as discussed below.

Sierra Pacific Resources and Nevada Power Company

Merrill Lynch/Allegheny Lawsuit

In May 2003, SPR and NPC filed suit against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc. and Allegheny Energy Supply Co., LLC (collectively, Allegheny) in the United States District Court, District of Nevada, for compensatory and punitive damages of $850 million for causing the PUCN to disallow the approximate $180 million rate adjustment for NPC in its 2001 deferred energy case (as discussed in Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K). The PUCN held that NPC acted imprudently when it refused to enter into an electricity supply contract with Merrill Lynch and subsequently paid too much for electricity from another source. SPR and NPC allege that Merrill Lynch and Allegheny’s fraudulent testimony and wrongful conduct caused the PUCN disallowance, among other allegations.

Merrill Lynch filed motions to dismiss in May 2003 and June 2003. Thereafter, the case was stayed pending resolution of NPC’s appeal of the 2001 deferred energy case pending before the Nevada Supreme Court, which was decided in August 2006 and discussed further in Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K. The Nevada District Court has yet to rule on the motions to dismiss. In October 2006, the District Court approved a stipulation continuing a stay of the proceeding pending final resolution of the PUCN remand proceedings in the 2001 deferred energy case. In May 2007, SPR and NPC filed a motion to amend their complaint to reflect the Nevada Supreme Court’s decision in the appeal and include additional damages (Motion to Amend). In June 2007, Allegheny and Merrill Lynch filed a motion in opposition to SPR and NPC’s Motion to Amend before the Nevada District Court on the ground that the Utilities’ recovery of the $189.9 million in rates under the PUCN Order on remand from the Nevada Supreme Court is all that SPR and NPC are entitled to recover and otherwise for failure to file a timely amended complaint (Motion in Opposition). In July 2007 the Court denied Allegheny and Merrill Lynch’s Motion in Opposition and further set the case for trial in July 2008. In February 2008, Merrill Lynch and Allegheny asked the Court to consider and rule on their originally filed motion to dismiss from 2003. In March 2008, Merrill Lynch and Allegheny filed new motions to dismiss at the order of the Court. NPC has filed oppositions to the new motions to dismiss in April 2008. Allegheny and Merrill Lynch filed reply briefs in late April 2008. Allegheny subsequently negotiated a settlement agreement with SPR and NPC in settlement of SPR and NPC's claims against Allegheny, which remains subject to a fairness hearing by the Court. The hearing date on Merill Lynch's motion to dismiss is scheduled for early May 2008. The Court set a trial date for July 2008. Management cannot predict the timing or outcome of a decision on this matter.

Nevada Power Company

Lawsuit Against Natural Gas Providers

In April 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders. In July 2003, SPR and NPC filed a First Amended Complaint. A Second Amended Complaint was filed in June 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric. On December 13, 2005, the District Court dismissed SPR and NPC’s claims. SPR and NPC appealed this decision to the Ninth Circuit Court of Appeals. Subsequently, SPR abandoned its appeal and the matter proceeded only with respect to NPC. In September 2007, the Ninth Circuit reversed the District Court’s order. In November 2007, the Ninth Circuit denied the gas providers and traders’ petition for rehearing. The Ninth Circuit has remanded the case to the District Court for further proceedings. In January 2008, the defendants refiled motions to dismiss, to which NPC responded in February 2008. Oral argument on the motions were heard and NPC is awaiting final order by the District Court. Management cannot predict the timing or outcome of a decision on this matter.

Sierra Pacific Power Company

Piñon Pine

SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). In March 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. In June 2006, the District Court granted PUCN’s motion to stay the Order. In July 2006, the Supreme Court issued an order questioning the finality of the District Court’s decision and thus whether it has jurisdiction over the appeal and invited the parties to brief this matter. The BCP and PUCN responded in early August 2006. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and in January 2007, the matter was remitted back to the District Court, which, consistent with its January 2006 order, remanded the matter back to the PUCN for further review.

The PUCN opened a docket to address the remand in April 2007. Briefs were filed and a hearing was held in January 2008. In March 2008, the PUCN issued an order finding approximately $6.1 million ($5.8 million Nevada Jurisdiction) of the $43 million in costs previously disallowed were just and reasonable and therefore recoverable in rates. As a result, SPPC recorded the Nevada portion as a regulatory asset, discounted in accordance with SFAS 90 Accounting for Abandonments and Disallowances of Plant Costs. The time for any party to appeal the PUCN’s decision ends in June 2008.

Environmental

Reid Gardner Station

Surface and Groundwater Matters

In February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3 and as co-owner and Operating Agent of Unit No. 4. The AOC was designed to supersede previous agreements for remedial activities at the site and take a comprehensive approach to address historical environmental impacts associated with facility operations. As a result of the AOC, NPC has recorded as an asset retirement obligation of approximately $20 million, which it expects to receive regulatory recovery of, similar to other Asset Retirement Obligations. Other costs are expected to include capital expenditures and remediation costs of approximately $32.3 million and operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is initiated and additional characterization is completed.

NEICO

ITEM 1A RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to SPR 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 2007 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 SPR’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2007, except as discussed below.

The Utilities plan to make significant capital expenditures to construct new generation and transmission facilities. If we are unable to finance such construction or limit the amount of capital expenditures associated with those facilities to forecasted levels, and/or recover amounts spent on construction through future filings with the PUCN, our financial condition and results of operation could be adversely affected.

Our long term business objectives include plans to construct new generation and transmission facilities. Such construction will require significant capital expenditures that the Utilities may finance through significant additional borrowings under the Utilities’ respective credit facilities, through additional debt financings in private or public offerings or through debt or equity financings by SPR. We cannot be sure that we will be able to obtain financing for such capital expenditures on favorable terms, or at all. Neither can we be sure that we will be successful in limiting capital expenditures to planned amounts, particularly in the event of escalating costs for materials, labor and environmental compliance, including the escalating costs for materials, labor and environmental compliance in connection with the construction of coal generation facilities as a result of timing delays and other economic factors. If we cannot obtain favorable financing arrangements for our planned capital expenditures, limit such capital expenditures to forecasted amounts and/or recover amounts spent on construction through future filings with the PUCN, our financial condition and results of operation would be adversely affected.

If SPR cannot maintain the required level of renewable energy or procure sufficient solar energy to meet Nevada’s increasing renewable energy Portfolio Standard the PUCN may, among other things, impose an administrative fine for noncompliance.

Nevada law sets forth the renewable energy portfolio standard (Portfolio Standard) requiring providers of electric service to acquire, generate, or save from renewable energy systems or energy efficiency measures a specific percentage of its total retail energy sales from renewable energy sources, including biomass, geothermal, solar, waterpower and wind projects. The Portfolio Standard requires the energy acquired from a renewable energy system be transmitted or distributed via a power line which is connected to a facility or system, owned, operated or controlled by the Utilities. Other restrictions are placed on energy acquired from energy efficiency measures which may not exceed more than 25 percent of the Portfolio Standard, including a requirement that half of those savings must come from residential customers.

In years 2007 and 2008, the Portfolio Standard requires that nine percent (9%) of total retail energy sales come from renewable energy. The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015. Moreover, not less than 5% of the total Portfolio Standard must be met by solar resources.

Due to periodic increases in the Portfolio Standard and increasing retail sales, the Utilities must acquire increasing amounts of renewable energy. The Utilities’ success in meeting the increasing Portfolio Standard remains largely dependent on their ability to acquire additional renewable energy from either self-owned renewable generation facilities or the purchase of renewable energy from third-party developers and a decrease in demand through qualified conservation and energy efficiency measures. In 2008, the Utilities reported to the PUCN in their Annual Report for Compliance Year 2007, that with the PUCN on approval of a sale and purchase of SPPC’s excess non-solar Portfolio Credit’s, both NPC and SPPC reported compliance with the non-solar Portfolio Standard. However, due to the late commercial operation of solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard. Although, historically, the Utilities have not been fined for non compliance, the PUCN may levy fines on one or both of the Utilities; however, management cannot predict the amount if any that could be imposed.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

Material Amendment to Compensatory Plan.

The 2008 Annual Meeting of the Stockholders of SPR was held at 10:00 a.m., Pacific Daylight Time, on Monday April 28, 2008, at the Las Vegas Hilton, Las Vegas, Nevada. All five proposals presented for stockholder consideration were approved, including:

·	a proposal to approve the material terms of the performance goals under SPR’s Amended and Restated Executive Long-Term Incentive Plan (“Restated LTIP”), and

·	a shareholder proposal.

Restated LTIP Performance Goals. SPR’s Executive Long-Term Incentive Plan (“LTIP”) was amended and restated by SPR’s Board of Directors on February 8, 2008, subject to stockholder approval of the material terms of the performance goals to, among other things, ensure that awards made pursuant to the Restated LTIP will not be subject to the deduction limits under Section 162(m) of the Internal Revenue Code of 1986 (“Code”). For purposes of Section 162(m) of the Code, the material terms of the performance goals of the Restated LTIP include: (i) the employees eligible to receive compensation, (ii) a description of the business criteria on which the performance goal is based and (iii) the maximum amount of compensation that can be paid.

The eligible participants under the Restated LTIP are the same as under the LTIP as approved by stockholders in 2004. As a result, no further stockholder approval was required.

The performance goals permitted by the Restated LTIP and approved by the stockholders are the following: total stockholder return; total stockholder return as compared to total return of a publicly available index; net income; pretax earnings; funds from operations; earnings before interest expense, taxes, depreciation and amortization; operating margin; earnings per share; return on equity, capital, assets or investment; operating expenses; working capital and/or liquidity; completion of capital projects; expense and/or liability containment; operating expenditures; operational safety metrics; energy supply, conservation and environmental performance; customer satisfaction metrics; service levels and reliability; shareholder profile metrics; ethics; public affairs and marketing metrics; ratio of debt to stockholders equity; workforce-related metrics; internal financial reporting and accounts payable metrics; and revenue. The achievement of a specified period of service may also be deemed a performance goal. The specific targets with respect to any performance goals will be determined in the Compensation Committee’s discretion.

Awards under the Restated Plan are subject to annual limits. Such limits apply to grants of awards in any one given calendar year to any participant as follows:


	Maximum Aggregate
	Number of Shares of
Type of Award	Common Stock

Options		45,000
Stock Appreciation Rights		45,000
Restricted stock		45,000
Performance Units		45,000	*
Performance Shares		45,000


*		Fair market value, determined on the date of grant, of 45,000 shares of Common Stock.

Additionally, the maximum aggregate amount of cash payments pursuant to performance units or other equity-based awards payable in cash under the Restated Plan that may be made in any one calendar year to any participant is $900,000.

Shareholder Proposal.

The shareholder proposal approved at the 2008 Annual Meeting of Stockholders requested the Directors of the Company to take the steps necessary to eliminate classification of the terms of the Board of Directors to require that all Directors stand for election annually. In light of the adoption of this proposal, the Board of Directors will undertake a review of the appropriate structure of the Board going forward, with the goal of providing recommendations for future shareholder action to consider the amendment of the Company’s Restated Articles of Organization.

The final voting results for each of the five proposals presented at the 2008 Annual Meeting of Stockholders will be disclosed in the Company’s Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2008.

Election of New Director.

On April 28, 2008, Maureen T. Mullarkey, recently retired executive vice president and chief financial officer of International Game Technology, was elected to SPR's board of directors, as well as NPC's and SPPC's board of directors. Ms. Mullarkey will serve on the Audit Committee and the Renewables, Conservation and Recycling Committee. Ms. Mullarkey will receive the same compensation and participate in the same plans as are provided to all of SPR’s non-employee directors, as more fully described in SPR’s definitive Proxy Statement filed on March 19, 2008.

ITEM 6. EXHIBITS

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

(12) Sierra Pacific Resources:

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) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

31.1 Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Annual Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3 Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4 Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.5 Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

32.1 Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3 Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4 Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.5 Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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.


	Sierra Pacific Resources
	(Registrant)

Date: April 29, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: April 29, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Nevada Power Company
	(Registrant)

Date: April 29, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: April 29, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Sierra Pacific Power Company
	(Registrant)

Date: April 29, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: April 29, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation

1-08788	SIERRA PACIFIC RESOURCES	88-0198358	Nevada
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

2-28348	NEVADA POWER COMPANY	88-0420104	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 367-5000

0-00508	SIERRA PACIFIC POWER COMPANY	88-0044418	Nevada
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

Sierra Pacific Resources:	Large accelerated filerþ	Accelerated filero	Non-accelerated filer o	Smaller reporting company o
Nevada Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filer þ	Smaller reporting company o
Sierra Pacific Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filer þ	Smaller reporting company o


Class		Outstanding at May 1, 2008
Common Stock, $1.00 par value of Sierra Pacific Resources		233,943,261 Shares

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED March 31, 2008


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

				Three Months Ended
				March 31,		Year Ended December 31,
				2008	2007	2007	2006	2005	2004	2003

EARNINGS AS DEFINED:
	Income (Loss) From Continuing Operations After Interest Charges			$ 24,058	$15,607	$ 197,295	$ 279,792	$ 86,137	$ 30,842	$(117,286)
	Income Taxes			16,708	10,628	87,555	145,605	43,118	18,050	(51,275)
	Income (Loss) From Continuing Operations before Income Taxes			40,766	26,235	284,850	425,397	129,255	48,892	(168,561)

	Fixed Charges			79,460	76,519	310,876	336,024	319,654	324,969	384,565
	Capitalized Interest (allowance for borrowed funds used during construction)			(9,152)	(5,334)	(25,967)	(17,119)	(24,691)	(8,587)	(5,976)
	Preferred Stock Dividend Requirement			-	-	-	(3,602)	(6,000)	(6,000)	(6,000)

			Total	$111,074	$ 97,420	$ 569,759	$ 740,700	$ 418,218	$359,274	$ 204,028

FIXED CHARGES AS DEFINED:
	Interest Expensed and Capitalized (1)			$ 79,460	$ 76,519	$ 310,876	$ 332,422	$ 313,654	$ 318,969	$ 378,565
	Preferred Stock Dividend Requirement			-	-	-	3,602	6,000	6,000	6,000

			Total	$ 79,460	76,519	310,876	336,024	319,654	$ 324,969	$ 384,565

RATIO OF EARNINGS TO FIXED CHARGES				1.40	1.27	1.83	2.20	1.31	1.11

		DEFICIENCY		$ -	$ -	$ -	$ -	$ -	$ -	$ 180,537

(1)		Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.