e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 2005


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


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

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether any registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Sierra Pacific Resources Yes þ No o; Nevada Power Company Yes o No þ; Sierra Pacific Power Company Yes o No þ

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


Class Common Stock, $1.00 par value of Sierra Pacific Resources		Outstanding at August 5, 2005 117,652,033 Shares

Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	June 30,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,750,900	$	6,604,449
Less accumulated provision for depreciation		2,167,112		2,083,434

		4,583,788		4,521,015
Construction work-in-progress		609,920		405,911

		5,193,708		4,926,926

Investments and other property, net		65,373		64,596


Current Assets:
Cash and cash equivalents		393,437		266,328
Restricted cash and investments (Note 1)		76,310		88,452
Accounts receivable less allowance for uncollectible accounts:
2005-$38,425; 2004-$36,197		371,436		320,676

Deferred energy costs — electric (Note 1)		147,555		148,008
Deferred energy costs — gas (Note 1)		4,836		3,106
Materials, supplies and fuel, at average cost		83,261		76,193
Risk management assets (Note 6)		42,245		14,585
Deposits and prepayments for energy		51,819		54,767
Other		27,705		37,494

		1,198,604		1,009,609

Deferred Charges and Other Assets:
Goodwill (Note 9)		22,877		22,877
Deferred energy costs — electric (Note 1)		474,405		526,159
Deferred energy costs — gas (Note 1)		—		2,491
Regulatory tax asset		273,829		279,766
Other regulatory assets		479,150		487,762
Risk management regulatory assets — net (Note 6)		3,902		6,673
Unamortized debt issuance expense		63,610		67,204
Other		108,090		114,297

		1,425,863		1,507,229

Assets of Discontinued Operations		20,116		20,107

TOTAL ASSETS	$	7,903,664	$	7,528,467

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	1,497,751	$	1,498,616
Preferred stock		50,000		50,000
Long-term debt		3,892,525		4,081,281

		5,440,276		5,629,897

Current Liabilities:
Short-term borrowings (Note 4)		240,000		—
Current maturities of long-term debt		248,699		8,491
Accounts payable		223,568		179,559
Accrued interest		74,489		69,246
Dividends declared		1,040		1,046
Accrued salaries and benefits		22,995		28,547
Deferred income taxes		30,137		54,501
Risk management liabilities (Note 6)		14,948		9,902
Accrued taxes		7,033		5,470
Contract termination liabilities (Note 7)		305,186		303,460
Other current liabilities		42,406		38,702

		1,210,501		698,924

Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
Deferred income taxes		535,680		512,760
Deferred investment tax credit		40,434		42,064
Regulatory tax liability		39,133		40,575
Customer advances for construction		156,695		142,703
Accrued retirement benefits		74,142		67,907
Contract termination liabilities (Note 7)		37,299		36,753
Regulatory liabilities		267,088		257,495
Other		92,216		89,189

		1,242,687		1,189,446

Liabilities of Discontinued Operations		10,200		10,200

TOTAL CAPITALIZATION AND LIABILITIES	$	7,903,664	$	7,528,467

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
OPERATING REVENUES:
Electric	$	668,583		$	652,350		$	1,249,727		$	1,180,724
Gas		32,136			21,879			99,674			81,355
Other		319			3,191			611			3,458

		701,038			677,420			1,350,012			1,265,537

OPERATING EXPENSES:
Operation:
Purchased power		298,619			263,266			518,771			456,757
Fuel for power generation		107,838			114,109			217,840			217,266
Gas purchased for resale		23,024			14,482			76,504			62,399
Deferred energy costs disallowed		—			—			—			1,586
Deferral of energy costs — electric — net		13,641			38,942			53,757			86,831
Deferral of energy costs — gas — net		1,332			1,376			1,004			(31	)
Impairment of goodwill		—			—			—			11,695
Other		87,199			90,162			174,789			163,251
Maintenance		24,157			22,216			47,103			47,104
Depreciation and amortization		53,298			52,129			106,087			102,066
Taxes:		—
Income tax benefit		(1,683	)		(5,835	)		(9,513	)		(27,897	)
Other than income		12,720			11,839			23,829			23,690

		620,145			602,686			1,210,171			1,144,717

OPERATING INCOME		80,893			74,734			139,841			120,820

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		4,889			1,192			8,698			2,565
Interest accrued on deferred energy		5,909			5,981			12,017			12,530
Disallowed merger costs		—			—			—			(5,890	)
Disallowed plant costs		—			(47,092	)		—			(47,092	)
Other income		9,204			8,405			19,343			17,044
Other expense		(4,036	)		(3,105	)		(8,302	)		(6,230	)
Income (taxes) / benefits		(7,668	)		12,356			(10,932	)		10,798

		8,298			(22,263	)		20,824			(16,275	)

Total Income Before Interest Charges		89,191			52,471			160,665			104,545

INTEREST CHARGES:
Long-term debt		78,579			85,719			157,006			161,179
Other		6,515			9,361			12,681			30,948
Allowance for borrowed funds used during construction		(5,928	)		(1,667	)		(10,531	)		(3,840	)

		79,166			93,413			159,156			188,287


INCOME / (LOSS) FROM CONTINUING OPERATIONS		10,025			(40,942	)		1,509			(83,742	)

DISCONTINUED OPERATIONS:

Income / (Loss) from discontinued operations (net of income taxes (benefits) of $0, $1,565, $(3) and $1,928 respectively)		1			(2,967	)		6			(3,642	)

NET INCOME / (LOSS)		10,026			(43,909	)		1,515			(87,384	)
Preferred stock dividend requirements of subsidiary		975			975			1,950			1,950

EARNINGS / (DEFICIT) APPLICABLE TO COMMON STOCK	$	9,051		$	(44,884	)	$	(435	)	$	(89,334	)


Amount per share basic and diluted — (Note 8)
Income / (Loss) from continuing operations	$	0.05		$	(0.35	)	$	0.01		$	(0.71	)
Earnings / (Deficit) applicable to common stock	$	0.05		$	(0.38	)	$	0.00		$	(0.76	)

Weighted Average Shares of Common Stock Outstanding — basic		183,338,153			117,279,506			117,569,589			117,259,726

Weighted Average Shares of Common Stock Outstanding — diluted		183,761,812			117,279,506			117,569,589			117,259,726

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)


	For the six months ended
	June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	1,515		$	(87,384	)
Non-cash items included in net income (loss):
Depreciation and amortization		106,087			102,066
Deferred taxes and deferred investment tax credit		1,393			(41,032	)
AFUDC and capitalized interest		(19,229	)		(6,405	)
Amortization of deferred energy costs — electric		88,720			124,122
Amortization of deferred energy costs — gas		(666	)		2,692
Deferred energy costs disallowed		—			1,586
Goodwill impairment		—			11,695
Loss on disposal of discontinued operations		—			2,346
Plant costs disallowed		—			47,092
Other non-cash		19,270			(44,410	)
Changes in certain assets and liabilities:
Accounts receivable		(50,759	)		(67,506	)
Deferral of energy costs — electric		(36,514	)		(49,803	)
Deferral of energy costs — gas		1,427			(2,742	)
Materials, supplies and fuel		(7,068	)		4,668
Other current assets		12,736			(14,353	)
Accounts payable		44,008			16,956
Escrow payment for terminating suppliers		—			(60,351	)
Other current liabilities		4,990			20,251
Change in net assets of discontinued operations		(8	)		2,267
Other assets		(28,082	)		12,900
Other liabilities		10,735			8,396

Net Cash from (used by) Operating Activities		148,555			(16,949	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(364,642	)		(184,615	)
AFUDC and other charges to utility plant		19,229			6,405
Customer advances for construction		13,992			8,011
Contributions in aid of construction		7,535			12,428

Net cash used for utility plant		(323,886	)		(157,771	)
Investments in subsidiaries and other property — net		3,452			3,814

Net Cash used by Investing Activities		(320,434	)		(153,957	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (Decrease) in short-term borrowings		240,000			(25,000	)
Change in restricted cash and investments		12,142			15,684
Proceeds from issuance of long-term debt		50,000			575,000
Retirement of long-term debt		(2,916	)		(525,371	)
Sale of common stock, net of issuance cost		1,727			650
Dividends paid		(1,965	)		(1,945	)

Net Cash from Financing Activities		298,988			39,018


Net Increase (Decrease) in Cash and Cash Equivalents		127,109			(131,888	)
Beginning Balance in Cash and Cash Equivalents		266,328			181,757

Ending Balance in Cash and Cash Equivalents	$	393,437		$	49,869


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	162,253		$	183,908
Noncash Activities:
Transfer of Regulatory Asset	$	—		$	294,468

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	June 30,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	4,127,274	$	4,015,125
Less accumulated provision for depreciation		1,158,584		1,112,335

		2,968,690		2,902,790
Construction work-in-progress		541,777		355,431

		3,510,467		3,258,221


Investments and other property, net		31,868		30,809


Current Assets:
Cash and cash equivalents		72,672		243,323
Restricted cash (Note 1)		50,311		50,311
Accounts receivable less allowance for uncollectible accounts:
2005-$32,850; 2004-$30,900		244,415		178,077
Deferred energy costs — electric (Note 1)		104,365		126,074
Materials, supplies and fuel, at average cost		45,965		44,858
Risk management assets (Note 6)		27,095		5,092
Deposits and prepayments for energy		26,768		23,091
Other		21,293		23,721

		592,884		694,547

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		351,412		375,120
Regulatory tax asset		163,091		167,221
Other regulatory assets		274,011		277,450
Risk management regulatory assets — net (Note 6)		7,306		3,555
Unamortized debt issuance expense		41,376		43,802
Other		20,638		32,815

		857,834		899,963

TOTAL ASSETS	$	4,993,053	$	4,883,540

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,423,125	$	1,436,788
Long-term debt		2,113,497		2,275,690

		3,536,622		3,712,478

Current Liabilities:
Current maturities of long-term debt		216,299		6,091
Accounts payable		156,609		114,242
Accounts payable, affiliated companies		3,311		3,920
Accrued interest		45,524		40,677
Dividends declared		397		399
Accrued salaries and benefits		9,949		12,780
Deferred income taxes		24,511		36,981
Risk management liabilities (Note 6)		9,738		3,555
Accrued taxes		3,601		2,441
Contract termination liabilities (Note 7)		212,825		211,620
Other current liabilities		31,588		27,651

		714,352		460,357

Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
Deferred income taxes		323,911		308,302
Deferred investment tax credit		17,827		18,642
Regulatory tax liability		16,062		16,506
Customer advances for construction		88,688		79,243
Accrued retirement benefits		24,491		21,025
Contract termination liabilities (Note 7)		35,364		34,847
Regulatory liabilities		172,724		171,330
Other		63,012		60,810

		742,079		710,705


TOTAL CAPITALIZATION AND LIABILITIES	$	4,993,053	$	4,883,540

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)


	For the six months ended
	June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	12,936		$	(1,816	)
Non-cash items included in net income (loss):
Depreciation and amortization		61,163			58,730
Deferred taxes and deferred investment tax credit		6,010			2,089
AFUDC		(17,690	)		(2,988	)
Amortization of deferred energy costs		72,135			104,532
Deferred energy costs disallowed		—			1,586
Other non-cash		17,670			(27,425	)
Changes in certain assets and liabilities:
Accounts receivable		(66,339	)		(84,307	)
Deferral of energy costs		(26,718	)		(32,598	)
Materials, supplies and fuel		(1,107	)		(535	)
Other current assets		(1,249	)		(8,918	)
Accounts payable		41,758			25,236
Escrow payment for terminating suppliers		—			(49,637	)
Other current liabilities		7,113			13,263
Other assets		(25,544	)		5,968
Other liabilities		5,736			(5,803	)

Net Cash from (used by) Operating Activities		85,874			(2,623	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(305,793	)		(132,565	)
AFUDC and other charges to utility plant		17,690			2,988
Customer advances for construction		9,445			4,468
Contributions in aid of construction		295			5,224

Net cash used for utility plant		(278,363	)		(119,885	)
Investments in subsidiaries and other property — net		(917	)		(120	)

Net Cash used by Investing Activities		(279,280	)		(120,005	)


CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Change in restricted cash and investments		—			2,600
Proceeds from issuance of long-term debt		50,000			140,000
Retirement of long-term debt		(1,986	)		(131,303	)
Dividends paid		(25,259	)		(20,117	)

Net Cash from (used by) Financing Activities		22,755			(8,820	)


Net Decrease in Cash and Cash Equivalents		(170,651	)		(131,448	)
Beginning Balance in Cash and Cash Equivalents		243,323			144,897

Ending Balance in Cash and Cash Equivalents	$	72,672		$	13,449


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	85,213		$	81,435

Noncash Activities:
Transfer of Regulatory Asset	$	—		$	197,998

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	June 30,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,623,626	$	2,589,324
Less accumulated provision for depreciation		1,008,528		971,099

		1,615,098		1,618,225
Construction work-in-progress		68,143		50,480

		1,683,241		1,668,705


Investments and other property, net		975		999


Current Assets:
Cash and cash equivalents		80,981		19,319
Restricted cash (Note 1)		14,430		16,464
Accounts receivable less allowance for uncollectible accounts:
2005-$5,705; 2004-$5,296		126,693		142,359
Accounts receivable, affiliated companies		42,530		67,261
Deferred energy costs — electric (Note 1)		43,190		21,934
Deferred energy costs — gas (Note 1)		4,836		3,106
Materials, supplies and fuel, at average cost		37,285		31,335
Risk management assets (Note 6)		15,150		9,493
Deposits and prepayments for energy		25,052		31,676
Other		5,962		9,728

		396,109		352,675

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		122,993		151,039
Deferred energy costs — gas (Note 1)		—		2,491
Regulatory tax asset		110,738		112,545
Other regulatory assets		205,139		210,312
Risk management regulatory assets — net (Note 6)		—		3,118
Unamortized debt issuance expense		12,711		13,564
Other		12,461		8,872

		464,042		501,941

TOTAL ASSETS	$	2,544,367	$	2,524,320

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	719,795	$	705,395
Preferred stock		50,000		50,000
Long-term debt		962,801		994,309

		1,732,596		1,749,704

Current Liabilities:
Current maturities of long-term debt		32,400		2,400
Accounts payable		47,043		42,884
Accrued interest		9,638		9,604
Dividends declared		964		968
Accrued salaries and benefits		11,678		13,846
Deferred income taxes		12,603		17,138
Risk management liabilities (Note 6)		5,210		6,347
Accrued taxes		3,309		2,878
Contract termination liabilities (Note 7)		92,361		91,840
Other current liabilities		9,542		8,516

		224,748		196,421


Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
Deferred income taxes		307,533		314,448
Deferred investment tax credit		22,607		23,422
Regulatory tax liability		23,071		24,069
Customer advances for construction		68,007		63,460
Accrued retirement benefits		40,444		41,558
Risk management regulatory liability — net (Note 6)		3,404		—
Contract termination liabilities (Note 7)		1,935		1,906
Regulatory liabilities		94,364		86,165
Other		25,658		23,167

		587,023		578,195

TOTAL CAPITALIZATION AND LIABILITIES	$	2,544,367	$	2,524,320

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)


	For the six months ended
	June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	17,036		$	(24,516	)
Non-cash items included in net income (loss):
Depreciation and amortization		44,924			43,336
Deferred taxes and deferred investment tax credit		(11,456	)		(18,772	)
AFUDC		(1,539	)		(3,417	)
Amortization of deferred energy costs — electric		16,585			19,591
Amortization of deferred energy costs — gas		(666	)		2,692
Plant costs disallowed		—			47,092
Other non-cash		3,511			(7,410	)
Changes in certain assets and liabilities:
Accounts receivable		40,396			13,105
Deferral of energy costs — electric		(9,796	)		(17,205	)
Deferral of energy costs — gas		1,427			(2,742	)
Materials, supplies and fuel		(5,950	)		5,189
Other current assets		10,390			(5,975	)
Accounts payable		4,158			(7,631	)
Escrow payment for terminating supplier		—			(10,715	)
Other current liabilities		(677	)		2,868
Other assets		(2,538	)		6,932
Other liabilities		2,783			13,699

Net Cash from Operating Activities		108,588			56,121


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(58,848	)		(52,050	)
AFUDC and other charges to utility plant		1,539			3,417
Customer advances for construction		4,547			3,543
Contributions in aid of construction		7,240			7,203

Net cash used for utility plant		(45,522	)		(37,887	)
Disposal of subsidiaries and other property — net		24			24

Net Cash used by Investing Activities		(45,498	)		(37,863	)


CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Decrease in short-term borrowings		—			(25,000	)
Change in restricted cash and investments		2,034			2,141
Proceeds from issuance of long-term debt		—			100,000
Retirement of long-term debt		(1,508	)		(98,503	)
Dividends paid		(1,954	)		(1,945	)

Net Cash used by Financing Activities		(1,428	)		(23,307	)


Net Increase (Decrease) in Cash and Cash Equivalents		61,662			(5,049	)
Beginning Balance in Cash and Cash Equivalents		19,319			20,859

Ending Balance in Cash and Cash Equivalents	$	80,981		$	15,810


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	36,444		$	41,486
Noncash Activities:
Transfer of Regulatory Asset	$	—		$	96,470

The accompanying notes are an integral part of the financial statements

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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). SPC is a discontinued operation, and as such, is reported separately in the financial statements. 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 or footnote disclosure 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, 2004 (the “2004 10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the three months and six months ended June 30, 2005, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

Certain items previously reported have been reclassified to conform to the current year’s presentation. Previously reported net income (loss) and shareholders’ equity were not affected by these reclassifications.

Deferral of Energy Costs

NPC and SPPC implemented deferred energy accounting on March 1, 2001. Beginning January 2004, the California Public Utility Commission (CPUC) issued its decision which re-instituted the Energy Cost Adjustment (ECAC) mechanism for SPPC’s California electric business. The ECAC allows SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. See Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in NPC’s and SPPC’s 2004 10-K, for additional information regarding the implementation of deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of June 30, 2005 (dollars in thousands):


		NPC		SPPC		SPPC			SPR
Description	Recovery Periods	Electric		Electric		Gas			Total
Unamortized balances approved for collection in current rates⁽¹⁾
Electric – NPC Period 2	(effective 5/03, 3 years)	$	1,381						$	1,381
Electric – NPC Period 3	(effective 1/05, 27 months)		76,614							76,614
Electric – NPC Period 4	(effective 4/05, 2 years)		100,197							100,197
Electric – SPPC Period 3	(effective 6/05, 25.5 months)				36,196					36,196
Electric – SPPC Period 4	(effective 6/05, 1 year)				25,102					25,102
Natural Gas – Period 3	(effective 11/03, 2 years)						(224	)		(224	)
Natural Gas – Period 4	(effective 11/04, 1 year)						126			126
LPG Gas – Period 2							(1	)		(1	)
LPG Gas – Period 3							44			44
Balances pending PUCN approval							6,288			6,288
Cumulative CPUC balance					4,291					4,291
Balances accrued since end of periods submitted for PUCN approval			37,546		16,562		(1,397	)		52,711
Claims for terminated supply contracts ⁽²⁾			240,039		84,032					324,071

Total		$	455,777	$	166,183	$	4,836		$	626,796


Current Assets
Deferred energy costs — electric		$	104,365	$	43,190	$	—		$	147,555
Deferred energy costs — gas			—		—		4,836			4,836
Deferred Assets
Deferred energy costs — electric			351,412		122,993		—			474,405

Total		$	455,777	$	166,183	$	4,836		$	626,796

(1)		The references to electric/gas periods, effective dates and time periods represent the various annual filings, the date recovery began for each amount and the ordered recovery period. The recovery periods represent the original periods set by the PUCN. However, the actual recovery period may differ depending on actual sales.

(2)		Amounts related to claims for terminated supply contracts are discussed in Note 7 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies.

Restricted Cash and Investments

At June 30, 2005, restricted cash primarily represents cash restricted for 1) $10.9 million debt service payments for SPR’s $300 million convertible notes, discussed in Note 7, Long-Term Debt, of Notes to Financial Statements in SPR’s 2004 10-K, and 2) the aggregate $60 million collateral payments made by NPC and SPPC into escrow in connection with the stay of the Enron Judgment, as described in Note 7, Commitments and Contingencies of the Condensed Notes to Consolidated Financial Statements. The remaining amount consists of cash balances that SPR, NPC and SPPC are required to maintain to support their cash management activities due to their financial condition.

Stock Compensation Plans

At June 30, 2005, SPR had several stock-based compensation plans, which are described more fully in Note 13, Stock Compensation Plans, of Notes to Financial Statements in SPR’s 2004 10-K. SPR applies Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” in accounting for its stock option plans and in accordance with the disclosure only provisions of Financial Accounting Standards Board’s Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” and the updated disclosure requirements set forth in SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. Had compensation cost for SPR’s nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans, consistent with the accounting provisions of SFAS No. 123, SPR’s earnings (deficit) applicable to common stock would have changed to the pro forma amounts indicated below (dollars in thousands, except per share amounts):


		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2005			2004			2005			2004
Earnings (Loss) applicable to common stock, as reported	As reported	$	9,051		$	(44,884	)	$	(435	)	$	(89,334	)

Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	As reported	$	(343	)	$	(56	)	$	(288	)	$	268

Less: Total stock employee compensation expense determined under fair value based methods, net of related tax effects	Pro forma		(132	)		(12	)		56			305


Pro forma earnings (loss) applicable to common stock	Pro forma		8,840			(44,928	)		(779	)		(89,371	)


Basic earnings (loss) per share	As reported	$	0.05		$	(0.38	)	$	—		$	(0.76	)
	Pro forma	$	0.05		$	(0.38	)	$	(0.01	)	$	(0.76	)

Diluted earnings (loss) per share	As reported	$	0.05		$	(0.38	)	$	—		$	(0.76	)
	Pro forma	$	0.05		$	(0.38	)	$	(0.01	)	$	(0.76	)

Recent Pronouncements

The Securities and Exchange Commission (SEC) announced on April 14, 2005 that it was delaying implementation of SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R). Under SFAS 123R, registrants would have been required to implement the standard as of the beginning of the first interim or annual period that begins after June 15, 2005. The SEC’s new rule allows SPR to implement SFAS 123R at the beginning of the next fiscal year that begins after June 15, 2005, or periods beginning December 31, 2005. The SEC’s new rule does not change the accounting required by SFAS 123R. Amounts that were previously shown in footnote disclosure by SPR will now be recognized in the income statement. SPR intends to utilize the services of its actuaries to value share-based compensation.

In March 2005, the FASB issued FASB Interpretation No. FIN 47 “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (FIN 47), which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143 “Accounting for Asset Retirement Obligations”. Specifically, FIN 47 provides that an asset retirement obligation is conditional when either the timing and (or) method of settling the obligation is conditioned on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. Management is currently evaluating the effect that adoption of this interpretation will have on SPR’s and the Utilities’ financial position and results of operations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements—An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. SPR and the Utilities are currently evaluating the effect that the adoption of SFAS 154 will have on their results of operations and financial condition but do not expect it to have a material impact.

NOTE 2. SEGMENT INFORMATION

SPR’s 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 to 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 threshold for separate disclosure.

The net assets and operating results of SPC are reported as discontinued operations in the financial statements for 2005 and 2004. Accordingly, the segment information excludes financial information of SPC. SPR’s total assets changed significantly from the amounts reported in the 2004 10-K, mainly due to the cash received in SPR’s issuance of $240 million Floating Rate Notes, as discussed in Note 4, Short Term Borrowings. Of the proceeds, approximately $230.5 million was contributed to NPC in July 2005.

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 operating income. The accounting policies of the business segments are the same as those described in Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements in the 2004 10-K. Inter-segment revenues are not material (dollars in thousands).


Three Months Ended	NPC		SPPC		Total
June 30, 2005	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	451,384	$	217,199	$	668,583	$	32,136	$	319	$	701,038

Operating Income	$	54,031	$	21,076	$	75,107	$	634	$	5,152	$	80,893


Three Months Ended	NPC		SPPC		Total
June 30, 2004	Electric		Electric		Electric		Gas			Other		Consolidated
Operating Revenues	$	449,925	$	202,425	$	652,350	$	21,879		$	3,191	$	677,420

Operating Income	$	49,470	$	17,933	$	67,403	$	(41	)	$	7,372	$	74,734


Six Months Ended	NPC		SPPC		Total
June 30, 2005	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	805,518	$	444,209	$	1,249,727	$	99,674	$	611	$	1,350,012

Operating Income	$	77,296	$	44,939	$	122,235	$	6,290	$	11,316	$	139,841


Six Months Ended	NPC		SPPC		Total
June 30, 2004	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	776,458	$	404,266	$	1,180,724	$	81,355	$	3,458	$	1,265,537

Operating Income	$	70,470	$	41,008	$	111,478	$	4,526	$	4,816	$	120,820

NOTE 3. REGULATORY ACTIONS

Nevada Matters

Nevada Power Company 2004 Deferred Energy Case

On November 15, 2004, NPC filed an application with the PUCN seeking recovery for purchased fuel and power costs accumulated between October 1, 2003 and September 30, 2004, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $116 million, with a carrying charge. The application requested that the 2004 Deferred Energy Accounting Adjustment (DEAA) recovery begin with the expiration of the 2002 DEAA recovery, which was expected to occur in May 2006 and for the 2004 DEAA recovery period to be 22 months.

The application also requested an increase to the going-forward base tariff energy rate (BTER).

In concert with this 2004 DEAA filing, NPC filed a petition with the PUCN requesting that other pending DEAA rate changes be synchronized to change on April 1, 2005 in order to stabilize rates and reduce the number of rate changes. On December 28, 2004, the PUCN issued an order approving a stipulation reached by all parties that allows NPC to defer previously approved DEAA rate changes until April 1, 2005 coincident with the DEAA rate change that will result from the 2004 DEAA case.

The combined effect of the requested synchronization of multiple rate changes (going forward BTER increase, 2001 DEAA expiration, and 2003 DEAA initiation) resulted in a request for an overall rate decrease of 2.4%.

On February 22, 2005, a stipulation of the parties was filed with the PUCN resolving all issues in the case. The stipulation provides for an overall decrease of 0.6% in total rates with no disallowances. The PUCN approved the stipulation in total on March 16, 2005.

Nevada Power Company Amendments to its Integrated Resource Plan

Long Term Power Exchange

On April 18, 2005, NPC filed an application with the PUCN requesting authorization to enter into an agreement with the Southern Nevada Water Authority (SNWA) that will allow NPC to dispatch SNWA’s 25% capacity ownership in the Silverhawk generating plant. The eight year agreement gives NPC the ability to use 125MW of the Silverhawk capacity and in return NPC will supply 75MW of firm power to SNWA.

On May 19, 2005, the PUCN approved the Power Exchange Agreement.

Sierra Pacific Power Company 2005 Electric Deferred Energy Case

On January 14, 2005, SPPC filed an application with the PUCN seeking recovery for purchased fuel and power costs accumulated between December 1, 2003 and November 30, 2004, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $27.7 million, with a carrying charge. The application requested that the 2005 DEAA recovery begin on June 1, 2005 together with the commencement of recovery of the 2004 DEAA balance both of which are coincident with the expiration of the 2002 and 2003 DEAA recovery. SPPC has requested a 24-month recovery period for the 2005 DEAA balance.

The application also requested an increase to the going-forward BTER.

The combined effect of the proposed synchronization of multiple rate changes (going forward BTER increase, 2002 and 2003 DEAA expiration, 2004 and 2005 DEAA initiation) resulted in a request for an overall rate increase of approximately 1.85%.

On March 30, 2005 SPPC filed an updated forecast of its going-forward BTER. If implemented, the new BTER, including the 2002 and 2003 DEAA expiration, and the 2004 and 2005 DEAA initiation, would result in an 8.73% overall rate increase.

On April 6, 2005, the PUCN Staff and the Bureau of Consumer Protection (BCP) filed written direct testimony in this case. The testimony recommended full recovery of the deferred balance after a $576 thousand reduction to reflect an accounting adjustment mutually agreed to by the parties. The PUCN Staff recommended adoption of the higher BTER rate that SPPC filed on March 30, 2005 while the BCP opposed the implementation of the higher BTER.

The PUCN issued its order on May 17, 2005 granting $27.1 million deferred expense recovery ($27.7 million requested less $.6 million), modifying the amortization period from the two years requested to one year and approving a BTER rate based on the historical costs methodology as provided for in the Nevada Administrative Code.

FERC Matters

Sierra Pacific Power Company 2004 Transmission Rate Case

On October 1, 2004, the Utilities filed with the FERC revised rates for transmission service offered by SPPC under Docket No. ER05-14. The purpose of the filing was to update rates to reflect recent transmission additions and to improve rate design. The participants in the proceeding have filed a Settlement Agreement with the FERC which has been certified by the Settlement judge. On May 6, 2005, the FERC issued an order approving the negotiated settlement.

NOTE 4. SHORT-TERM BORROWINGS

On June 20, 2005, SPR issued and sold $140,860,000 of its Series A Floating Rate Senior Notes, due November 16, 2005, and $99,140,000 of its Series B Floating Rate Senior Notes, due November 16, 2005 (the “Floating Rate Notes”). The Series A Floating Rate Notes will bear interest at a rate equal to 3-month LIBOR plus 2.00%, and the Series B Floating Rate Notes will bear interest at a rate equal to 3-month LIBOR plus 1.00%. The Floating Rate Notes were issued to Qualified Institutional Buyers under Rule 144A. Of the proceeds from this issuance, $230.5 million was used to make an equity contribution to NPC and the balance will be used for general corporate purposes. NPC used the equity contribution to redeem approximately $210 million of General and Refunding Mortgage Notes. See Note 5, Long-Term Debt for further discussion on the redemption by NPC.

SPR may redeem, at any time, all or a part of the Floating Rate Notes, without premium or penalty, upon not less than three, nor more than thirty days’ notice. Subject to certain limitations, additional Floating Rate Notes may be issued from time to time; provided, however, that the aggregate principal amount of Floating Rate Notes outstanding at any time may not exceed $240,000,000.

NOTE 5. LONG-TERM DEBT

As of June 30, 2005, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the balance of 2005, for the next four years and thereafter are shown below (dollars in thousands):


							SPR Holding Co.			SPR
	NPC			SPPC			and Other Subs.			Consolidated
2005	$	213,071	⁽²⁾	$	854		$	—		$	213,925
2006		6,509			52,400			—			58,909
2007		55,949	⁽³⁾		2,400			141,077			199,426
2008		7,066			322,400			—			329,466
2009		185,010			600			—			185,610

		467,605			378,654			141,077			987,336
Thereafter		1,871,005			617,250			734,141	⁽¹⁾		3,222,396

		2,338,610			995,904			875,218			4,209,732
Unamortized (Discount Amount)		(8,814	)		(703	)		(5,436	)		(14,953	)

Total	$	2,329,796		$	995,201		$	869,782		$	4,194,779

(1)

SPR’s “Thereafter” amount of $734 million includes the total amount of the 7.25% Convertible Notes due at maturity ($300 million). This differs from the carrying value of approximately $246 million included in the balance sheet amount of Long-term debt, which is being accreted to face value using the effective interest method.

(2)

NPC’s “2005” amount of $213 million includes $210 million of debt that was paid subsequent to June 30, 2005. See Financing Transactions below for details.

(3)

NPC’s “2007” amount of $55.9 million does not include an additional $50 million draw on the revolving credit facility made July 26, 2005.

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

Financing Transactions (SPR — Holding Company)

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of its $300 million outstanding 7.25% Convertible Notes (Notes) due 2010 to convert their Notes to shares of SPR common stock. Under the terms of the offer, for each $1,000 in liquidation amount of Notes tendered, holders will receive the conversion consideration and 219.1637 shares of common stock. The consideration offered is an amount paid in cash equal to $180 per $1,000 principal amount of Notes validly surrendered for conversion plus an amount equivalent to the interest that would have accrued thereon from and after August 14, 2005 (which is the last interest payment date on the Notes prior to the scheduled expiration of the offer). The offer will expire on August 31, 2005, unless extended or earlier terminated by SPR. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” an approximate $54 million cash payment will be expensed during the third quarter of 2005 which SPR expects to pay using the proceeds from long-term debt financing. This amount represents the cash consideration given beyond those required by the terms of the Notes. The amount of SPR common shares that would be issued if all the outstanding Notes are converted is 65,749,110 shares with an approximate $248 million increase to equity equal to the current carrying value of the Notes.

SPR issued $240 million of additional debt on June 20, 2005, as discussed above in Short-Term Borrowings.

On April 15, 2005, SPR commenced an offer to exchange its Premium Income Equity Securities (“old PIES”) for new Premium Income Equity Securities (“new PIES”) plus an exchange fee of $0.125 in cash for each old PIES tendered. On May 24, 2005, the tender offer was completed with 1,982,822 or about 41% of the 4,804,350 old PIES outstanding tendered for exchange. The remaining 2,821,528 old PIES will remain outstanding. SPR’s new PIES are similar to its old PIES except the new PIES (i) allow for the remarketing of the senior notes that are associated with the new PIES prior to the earliest remarketing date for the old PIES, (ii) provide for more flexible remarketing terms, and (iii) allow certain terms of the senior notes to be modified upon their remarketing, including the maturity date of the senior notes, the redemption provisions, the interest payment dates and the addition of covenants applicable to the senior notes.

On May 24, 2005, as part of the new PIES, SPR issued $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. SPR successfully remarketed these notes on June 14, 2005. In connection with the remarketing, the interest rate of the Senior Notes was reset to 7.803% per annum, effective on and after June 14, 2005. The remarketed Senior Notes will mature on June 15, 2012. The proceeds of the remarketing of the Senior Notes were used to purchase treasury securities and to pay the fee of the remarketing agents. The treasury securities will serve as substitute collateral for the Senior Notes component of the new PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the treasury securities upon or after maturity will be used to provide the consideration necessary to fulfill holders’ obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the new PIES through November 15, 2005.

Financing Transactions NPC

On July 14, 2005, NPC redeemed $87,500,000 aggregate principal amount of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, and $122,500,000 aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013. These redemptions constituted 35% of the principal amount outstanding of each of the Series E and Series G Notes. The Series E Notes were redeemed at a redemption price equal to $1,108.75 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $9.5 million. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt. NPC paid for the redemptions through an equity contribution of approximately $230.5 million from SPR, as discussed in Note 4, Short-Term Borrowings.

As of June 30, 2005 NPC had borrowed $50 million under its revolving credit facility. As of August 5, 2005, NPC had $100 million outstanding under the revolving credit facility. See Note 7, Long-Term Debt, of Notes to Financial Statements in the 2004 10-K for details of the revolving credit facility.

NOTE 6. DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC, and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 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 qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard.

SPR’s and the Utilities’ objective in using derivatives is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and marketing of power and the procurement and marketing of natural gas. Derivative instruments used to manage energy price risk from time to time may include forwards, options, and swaps. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

The following table shows the fair value of the derivatives recorded on the Consolidated Balance Sheets of SPR, NPC, and SPPC, and the related regulatory assets/liabilities. Due to deferred energy accounting 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 (dollars in millions):


	June 30, 2005							December 31, 2004
	SPR		NPC		SPPC			SPR		NPC		SPPC
Risk management assets	$	42.2	$	27.1	$	15.2		$	14.6	$	5.1	$	9.5
Risk management liabilities	$	14.9	$	9.7	$	5.2		$	9.9	$	3.6	$	6.3
Risk management regulatory assets (liabilities)	$	3.9	$	7.3	$	(3.4	)	$	6.7	$	3.6	$	3.1

Also included in risk management assets were $31.9 million, $24.7 million, and $7.2 million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at June 30, 2005.

NOTE 7. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Mohave Generation Station

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generation Station (Mohave), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006 for the first and second units, respectively. The estimated cost of new pollution controls and other capital investments is $1.2 billion. As a 14% owner in Mohave, NPC’s cost could be $168 million.

Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the “Tribes”). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE’s share of Mohave. On October 20, 2004, the CPUC issued a proposed decision which, among other things, directed SCE to continue negotiations with the Tribes regarding post-2005 coal and water supply, and directed SCE to conduct a study of potential alternatives to Mohave.

NPC’s ownership interest in Mohave comprises approximately 10% of NPC’s peak generation capacity. Because coal and water supplies necessary for long-term operation of Mohave have yet to be secured, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave’s operations are extended past 2005. Due to the lack of resolution of these coal and water supply issues with the tribes, it is not the intention of SCE and other owners to proceed with the installation of required pollution control equipment at this time. The owners intend to cease operation of the plant by January 1, 2006, pending resolution of these issues. It is the owners’ intent to preserve their ability to restart the plant at a later date should these issues be resolved, and economic analysis at that time support such a decision. See further discussion of issues related to Mohave below in Regulatory Contingencies.

Reid Gardner Station

In August 1999, 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 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. 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. Total new pond construction and lining costs are estimated at approximately $33 million, of which, approximately $20 million has been spent through 2004. Estimated total capital expenditures planned in 2005 and 2006 are approximately $6 million and $3 million, respectively. Year to date expenditures total approximately $.8 million.

At the Reid Gardner Station, NDEP has determined that there is additional groundwater contamination that resulted from diesel oil spills at the facility. NDEP required NPC to submit a corrective action plan. A hydro-geologic evaluation of the current remediation has been completed, and a dual phase extraction remediation system, which was approved by NDEP, commenced operation in October 2003. The remediation system remains in operation and this effort has shown positive response to cleaning up the diesel oil.

In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and on December 2, 2004 issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. On July 20, 2005, NDEP issued new Notices of Alleged Violations (NOAVs). In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. NPC is continuing to provide information to NDEP as requested and is engaged in an ongoing dialogue with NDEP, including settlement discussions. Because no penalty has been specified by NDEP and discussions are continuing, management cannot reasonably estimate the amount of any potential monetary penalties that may ultimately be assessed in connection with the alleged violations. On July 26, 2005 NPC received a letter from the EPA requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC is in the process of responding to the EPA information request.

Clark Station

In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. On October 31, 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur and management is presently involved in the discovery process to support this position. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time.

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. Currently, management is continuing to evaluate various options including reclamation and sale.

Sierra Pacific Power Company

In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which has completed site investigations and with the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA issued an administrative order on consent requiring the steering committee to oversee the performance of the work. The work to dismantle the buildings and dispose of

the debris and impacted soil is currently underway, and is expected to be complete in mid-2006. While the final cost to complete the work is not yet definite, SPPC’s share of the cost is not expected to be material.

Litigation

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

Brief Overview

Currently the Utilities are involved in a number of court cases and hearings involving Enron Power Marketing, Inc. (Enron). The cases are as follows: U.S. Bankruptcy Court for the Southern District Court of New York (Bankruptcy Court), U.S. District Court for the Southern District of New York (U.S. District Court); FERC hearings consisting of the FERC Early Termination, FERC Revocation Show Cause Proceeding and the FERC Gaming and Show Cause Proceeding. See details of the court cases and hearings below.

In 2003, based on the Judgment entered by the Bankruptcy Court (Judgment), NPC and SPPC recorded contract termination liabilities of $235 million and $103 million, including prejudgment interest of $27.8 million and $12.4 million, respectively. Additionally, in order to stay execution of the Judgment, NPC and SPPC have posted into escrow $186 million and $92 million, respectively, of General and Refunding Mortgage Bonds and $49 million and $11 million, respectively, in cash as of December 31, 2004. On October 10, 2004, in response to our appeal of the Judgment, the U.S. District Court rendered a decision vacating an earlier judgment by the Bankruptcy Court against the Utilities in favor of Enron, and remanded the case back to the Bankruptcy Court for fact-finding. Furthermore, the U.S. District Court held that the pre-judgment interest should have been calculated at the present value rate, rather than at the rate of 1% per month used by the Bankruptcy Court.

Based on the U.S. District Court’s decision, the Utilities reversed the accrued interest included in contract termination liabilities by approximately $40 million for the year ended 2004. Although the Judgment entered by the Bankruptcy Court has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron, discussed below, will remain in place through the pendency of all remands and appeals of the Judgment. If the Utilities are ultimately required to pay part or all of the amounts accrued, the Utilities will pursue recovery of the payments through future deferred energy filings. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amount not permitted would be charged as a current operating expense.

On August 8, 2005, President Bush signed the Domenici Barton Energy Policy Act into law (the “Energy Bill”). The Energy Bill contains language that relates to the Utilities’ disputes with Enron over termination payments Enron claims are owed to them arising from forward power purchase contracts terminated by Enron in 2002. The amendment grants FERC exclusive jurisdiction over the determination of whether any such payments are unjust, unreasonable or contrary to the public interest. The Utilities have not yet determined what impact the law will have on the status of the various ongoing legal proceedings at this time.

A description of the legal proceedings leading up to the U.S. District Court’s order to vacate follows, along with a discussion of all pending matters related to the Enron litigation.

Bankruptcy Court Judgment

On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy case in the U.S. Bankruptcy Court for the Southern District of New York asserting claims for termination payments Enron claimed it was owed under purchased power contracts with the Utilities. Enron sought liquidated damages in the amount of approximately $216 million from NPC and $93 million from SPPC based on assertions by Enron that it had contractual rights under the Western Systems Power Pool Agreement (WSPPA) to terminate deliveries to the Utilities. Enron based its assertion on a claim that the Utilities did not provide adequate assurance of the Utilities’ performance under the WSPPA. The Utilities dispute that they owe the monies sought by Enron and have denied liability on numerous grounds, including termination, deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.

On September 26, 2003, the Bankruptcy Court entered a summary judgment (the Judgment) in favor of Enron for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment required NPC and SPPC to pay approximately $235 million and $103 million, respectively, to Enron for liquidated damages and pre-judgment interest for power not delivered by Enron under the power supply contracts terminated by Enron in May 2002 and approximately $17.7 million and $6.7 million, respectively, for power previously delivered to the Utilities. Based on the pre-judgment rate of 12%, NPC and SPPC recognized additional interest expense of $27.8 million and $12.4 million, respectively, in contract termination liabilities in the third quarter 2003. Also, NPC and SPPC recorded additional contract termination liabilities for liquidated damages of $6.6 million and $2.1 million, respectively, in the third quarter of 2003. The Bankruptcy Court’s order provided that until paid, the amounts owed by the Utilities will accrue interest post-Judgment at a rate of 1.21% per annum.

into escrow $235 million and $103 million, respectively, of General and Refunding Mortgage Bonds plus approximately $282 thousand in cash by NPC for pre-judgment interest. On December 4, 2003, NPC and SPPC complied with the order of the Bankruptcy Court by issuing NPC’s $235 million General and Refunding Mortgage Bond, Series H plus SPPC’s $103 million General and Refunding Mortgage Bond, Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which would lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made the payments as ordered on February 10, 2004. The Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall seek a ruling from the PUCN to determine whether the cash payments into escrow trigger the Utilities’ rights to seek recovery of such amounts through the Utilities’ deferred energy rate cases.

On November 21, 2003, the Utilities filed a Petition for Declaratory Order with the PUCN, as required by the Bankruptcy Court’s stay order seeking a determination as to whether payment of all or part of the Judgment into escrow would be subject to recovery through a deferred energy accounting adjustment. On February 6, 2004, the PUCN issued its final order indicating that posting or depositing money in escrow would not constitute payment of fuel or purchased power costs eligible for recovery in a deferred account.

On April 5, 2004, Enron and the Utilities entered into a settlement whereby NPC agreed to post an additional cash sum of $25 million to be held in escrow pending the issuance of the U.S. District Court’s opinion and Enron agreed not to request any additional collateral from NPC or SPPC during the pendency of the Utilities’ appeal of the Judgment to the U.S. District Court for the Southern District of New York. NPC made the agreed-upon payment on April 16, 2004, which lowered the principal amount of NPC’s General and Refunding Mortgage Bond, Series H, currently held in escrow, by a like amount.

The Utilities entered into a stipulation and agreement with Enron which was signed by the Bankruptcy Court on June 30, 2004 which provides that (1) the Utilities shall withdraw their objections to the confirmation of Enron’s bankruptcy plan, (2) the collateral contained in the Utilities’ escrow accounts securing their stay of execution of the Judgment shall not be deemed property of Enron’s bankruptcy estate or the Utilities’ estates in the event of a bankruptcy filing, and (3) the stay of execution of the Judgment, as previously ordered by the Bankruptcy Court, shall remain in place without any additional principal contributions by the Utilities to their existing escrow accounts during the pendency of any and all of their appeals of the Judgment, including to the United States Supreme Court, until a final non-appealable judgment is obtained. There can be no assurances that the U.S. District Court or any higher court to which the Utilities appeal the Judgment will accept the existing collateral arrangement to secure further stays of execution of the Judgment.

On October 15, 2004, the Bankruptcy Court ruled that Enron was entitled to take the $17.7 million and $6.7 million deposited by NPC and SPPC, respectively, for power previously delivered to them, out of escrow for the benefit of Enron’s bankruptcy estate. The Utilities have challenged the Bankruptcy Court’s order with respect to these payments, and no final ruling has been made by the Bankruptcy Court.

Appeal of Bankruptcy Court Judgment to U.S. District Court

On October 1, 2003, the Utilities filed a Notice of Appeal from the Judgment with the U.S. District Court, Southern District of New York. In the Utilities’ appeal, the Utilities sought reversal of the Judgment and contended that Enron is not entitled to recover termination charges under the contracts on various grounds including breach of contract, breach of solvency representation, fraud, misrepresentation, and manipulation of the energy markets and that the Bankruptcy Court erred in holding that the filed rate doctrine barred various claims which were purported to challenge the reasonableness of the rate. Enron filed a cross-appeal on the grounds that the amount of post-judgment interest should have been 12% per year instead of 1.21% as ordered by the Bankruptcy Court.

On October 10, 2004, the U.S. District Court rendered a decision in the Utilities’ appeal. The U.S. District Court’s decision vacated the judgment entered by the Bankruptcy Court against the Utilities in favor of Enron and remanded the case to the Bankruptcy Court for fact-finding on several issues including:

	•		whether Enron’s demand for assurances at the time of termination of its power supply contracts with NPC and SPPC was reasonable;

	•		whether the assurances offered by NPC and SPPC to Enron were “reasonably satisfactory assurances”; and

	•		whether Enron would have been able to perform all of its obligations under each of the power supply contracts at the time the contracts were terminated and following termination.

The U.S. District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The U.S. District Court rejected Enron’s cross-appeal seeking a 12% per year post-judgment interest rate instead of the 1.21% interest rate ordered by the Bankruptcy Court. The U.S. District Court decision also provided that Enron could, if proper, renew its motion to enjoin the proceedings currently before the FERC addressing Enron’s termination of its power supply contracts with NPC and SPPC. Although the Judgment has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron, discussed above, will remain in place through the pendency of all remands and appeals of the Judgment.

The Utilities filed a motion seeking clarification of the U.S. District Court rulings with respect to the Utilities’ affirmative defenses and counterclaims regarding: fraud by Enron, violation of the Racketeer Influence Corrupt Organizations Act (RICO), anti-trust activities carried out by Enron, the constitutional power of a bankruptcy court to enter a final judgment in a “non-core matter,” and whether the Bankruptcy Court had properly determined the interest rate applicable to pre-judgment interest. This motion did not relate to Enron’s claims against the Utilities, which the U.S. District Court addressed in its October 10, 2004 decision described above. On December 23, 2004, the U.S. District Court ruled on this motion, affirming the dismissal of the Utilities’ affirmative defenses and counterclaims on the grounds that they were barred under the filed rate doctrine. However, the U.S. District Court ruled in favor of the Utilities on the calculation of pre-judgment interest.

FERC Early Termination Case

On October 6, 2003, the Utilities filed a Complaint with FERC requesting the opportunity to develop a record regarding three issues: (a) whether Enron exercised reasonable discretion in terminating its various purchased power contracts with the Utilities; (b) whether FERC should exercise its authority to find that Enron is not entitled to collect termination payment profits; and (c) whether Enron should be otherwise denied the authority to collect such payments because to do so would be contrary to the public interest.

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. Hearings were scheduled to begin on October 25, 2004 and an initial decision was expected from the FERC by December 31, 2004. However, on October 27, 2004, Enron filed a motion in the Bankruptcy Court to enjoin the Utilities from participating in the FERC Early Termination Case. The disposition of this motion is described below.

Bankruptcy Court Injunction and Order Setting Trial

After the U.S. District Court issued its October 10, 2004 ruling, Enron renewed its motion with the Bankruptcy Court seeking to enjoin the Utilities from proceeding in the FERC Early Termination Case. On December 3, 2004, the Bankruptcy Court enjoined the Utilities from further prosecution of the scheduled hearing in the FERC proceeding. The Utilities have appealed this decision and are seeking a stay of the trial in Bankruptcy Court pending the outcome of the FERC Early Termination Case. The trial was initially set for July 11, 2005, but the trial date has been changed to November 7, 2005. The Utilities are unable to predict the outcome of these proceedings at this time.

FERC Revocation Show Cause Proceeding

In March 2003, FERC instituted a “Show Cause” proceeding involving whether Enron’s market-based rate authority should be revoked in light of Enron’s engagement in illicit trading activities. The Utilities intervened in the FERC’s proceeding against Enron. On June 25, 2003, FERC removed Enron’s market-based rate authority, but only on a prospective basis. The Utilities filed a request for rehearing, along with certain other parties. On October 16, 2003, FERC changed the nature of the proceeding, thereby prohibiting further active participation by the interveners (including the Utilities). On December 15, 2003, the Utilities filed an appeal in the United States Circuit Court of Appeals for the District of Columbia (D.C. Circuit) concerning these two actions. The appeals have been consolidated with a number of other appeals of FERC’s decisions, and the matter is pending. The D.C. Circuit has yet to establish a briefing schedule and there is no current time line for argument or a decision in the case.

FERC Gaming and Partnership Show Cause Proceeding

On June 25, 2003, FERC issued orders in two separate cases involving Enron, among others, and potential gaming of power markets. The first was referred to as the “Gaming Show Cause Proceeding” and the second as the “Partnership Show Cause Proceeding”. The proceedings focused on Enron’s illicit trading activity in California with a variety of counterparties. On July 21, 2004, FERC consolidated the two proceedings and expanded the scope of its inquiry. FERC announced that it was revisiting its decision not to revoke Enron’s market-based rate authority retroactively and that “Enron potentially could be required to disgorge profits for all of its wholesale power sales in the Western Interconnect for the period January 16, 1997 to June 15, 2003.” Enron has sought rehearing of this order, challenging the expanded scope of the proceeding. The Utilities have joined a coalition of other Western Parties and on August 4, 2004, sought clarification that

remedies other than disgorgement might be available. On March 11, 2005, the FERC issued an order clarifying issues to be covered in the administrative trial. In that order, the FERC stated that Enron’s profits under the terminated power contracts fell within the scope of that proceeding. On July 20, 2005, the FERC issued an order in the Gaming and Partnership Show Cause Proceeding involving Enron, among others, suspending the trial schedule, including the September 7, 2005 trial date, pending FERC review of a recent settlement agreement between the California parties and Enron. The order provides that the trial in this proceeding will convene within seven weeks following FERC’s review of the proposed settlement. FERC also ordered Enron not to take any action to move forward the Bankruptcy Court proceeding, and ordered it to join in any request for postponement of any filing or action in the Bankruptcy Court proceeding. In addition, FERC ordered the remaining parties, including NPC and SPPC, to participate in settlement negotiations.

The FERC proceeding focuses on Enron’s illicit trading activity in California with various counterparties, including the People of the State of California, California state entities, California utilities and other non-Californian entities (including NPC and SPPC). NPC and SPPC are unable at this time to predict the outcome of the upcoming settlement negotiations, or, if settlement negotiations prove unsuccessful, the outcome of the trial.

FERC 206 Complaints

In December 2001, the Utilities filed ten complaints with the FERC under Section 206 of the Federal Power Act seeking to reduce prices of certain forward wholesale power purchase contracts that the Utilities entered into prior to the price caps imposed by the FERC in June 2001 relating to the western United States energy crisis. The Utilities believe the prices under these purchased power contracts are unjust and unreasonable. The Utilities negotiated a settlement with Duke Energy Trading and Marketing, but were unable to reach agreement in bilateral settlement discussions with other respondents.

The Utilities are contesting the amounts paid for power actually delivered by these suppliers as well as claims made by terminating power suppliers that did not deliver power, including Enron.

On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints finding that the strict public interest standard applied to the case and that the company had failed to satisfy the burden of proof required by that standard. On July 28, 2003, the Utilities filed a petition for rehearing at the FERC requesting that the FERC either reconsider or rehear the case. On November 10, 2003, the FERC reaffirmed the June 26, 2003, decision. That decision has been appealed to the United States Court of Appeals for the Ninth Circuit. Oral argument was held on December 8, 2004 and a decision is pending. The Utilities are unable to predict the outcome of this appeal at this time.

Reliant and Duke Antitrust Litigation

Reliant Energy Services, Inc. (Reliant) served a cross-complaint against NPC and SPPC and Duke Energy Trading and Marketing, LLC (Duke) served a cross-complaint against Sierra Pacific Resources in the wholesale electricity antitrust cases on April 22, 2002 and April 23, 2002, respectively. These cases were consolidated in the Superior Court of the State of California. Plaintiffs (original plaintiffs consist of The People of the State of California, City and County of San Francisco, City of Oakland, and County of Santa Clara) seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a competitive market.

Reliant and Duke filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there was liability, it should be spread among all energy suppliers. Despite efforts by various cross-defendants to remove the case to federal court and following an appeal with the Ninth Circuit Court of Appeals, the case was ultimately remanded back to the Superior Court of the State of California in May 2005. The case is currently active and a scheduling order has been set. SPR maintains that Duke agreed to dismiss its cross-complaint pursuant to settlement and release agreement dated June 4, 2002. SPR, NPC and SPPC believe they should have no liability regarding either matter, but at this time management is not able to predict either the outcome or timing of a decision.

Nevada Power Company

Morgan Stanley Proceedings

On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated arbitration pursuant to arbitration provisions in various power supply contracts that were terminated by MSCG in April 2002. MSCG requested that the arbitrator award $25 million for termination payments, pending the outcome of the subject power supply contract disputes with NPC. NPC claimed it did not owe payment under the contracts on various grounds, including breach by MSCG in terminating the contracts and lack of jurisdiction by the arbitrator. In March 2003, the arbitrator dismissed MSCG’s demand for arbitration and agreed that the issues raised by MSCG and NPC’s contract defenses were not arbitrable.

NPC filed a complaint for declaratory relief in the U.S. District Court, District of Nevada seeking a declaration stating NPC is not liable for any damages resulting from MSCG’s termination of the power supply contracts. On April 17, 2003, MSCG filed an answer and a counterclaim seeking $25 million in termination payments. Furthermore, MSCG filed a complaint against NPC at the FERC seeking termination payments from NPC pending resolution of the civil case. In addition, MSCG filed a motion to intervene in the Section 206 action commenced by NPC against Enron at the FERC, which motion the FERC denied. On October 23, 2003, NPC filed a motion to stay the District Court proceedings seeking declaratory relief, pending guidance on applicable legal principles to be provided by the FERC in connection with NPC’s litigation against Enron regarding the exercise of default and early termination rights. In February, 2004, the District Court granted NPC’s motion. In August, 2004, upon motion by NPC, the District Court continued the stay. In February, 2005, the Judge ordered the case to go forward, at which time NPC filed a motion for summary judgment. In March, 2005, MSCG similarly filed for summary judgment. The District Court denied both summary judgment motions, stating that there are serious factual questions that must be addressed about the reasonableness of MSCG’s termination of the 28 contracts, which determination will be made upon completion of discovery (currently scheduled for November 30, 2005). A court ordered settlement conference is currently scheduled for the third quarter of 2005. A trial date is scheduled for January 10, 2006. The Court further ordered that NPC pay MSCG for the approximately $1.8 million (plus interest) for power delivered prior to the termination. NPC anticipates payment in the third quarter of 2005. At this time, NPC is unable to predict the outcome or timing of the matter.

El Paso Merchant Energy

In September 2002, El Paso Merchant Energy (EPME) terminated all forward contracts for energy with NPC for alleged defaults under the WSPPA consisting of alleged failure to pay full contract price for power under NPC’s “delayed” payment program which extended from May 1 to September 15, 2002. In October 2002, EPME asserted a claim against NPC for $29 million in damages representing $19 million unpaid under contracts for delivered power during the period May 15 to September 15, 2002, together with approximately $10 million in alleged mark to market damages for future undelivered power. The amount presently claimed by EPME is $42 million, including interest. NPC alleges that EPME’s termination resulted in net payments due to NPC under the WSPPA for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. The precise amount due would depend on the manner in which the termination payments are calculated.

In June 2003, EPME demanded mediation of its claim for a termination payment arising out of EPME’s September 25, 2002, termination of all executory purchase power contracts between NPC and EPME. The mediation was unsuccessful, and on July 25, 2003, NPC commenced an action against EPME and several of its affiliates in the Federal District Court for the District of Nevada for damages and declaratory relief resulting from breach of these purchase power contracts. EPME filed a motion for summary judgment in April 2005. NPC opposed the motion which is now pending before the District Court. The case is set for trial to commence in September 2005. At this time, NPC is unable to predict either the outcome or timing of a decision in this matter.

Peabody Western Coal Company

NPC owns an 11%, 255 MW interest in the Navajo Generating Station (Navajo) located in Northern Arizona. Besides NPC, the Salt River Project (Salt River), Arizona Public Service Company, Los Angeles Department of Water and Power, and Tucson Electric Power Company (together the Joint Owners), are participants in Navajo, which includes three coal-fired electrical generating units operated by Salt River.

In January 2005, the Joint Owners were served with a complaint from Peabody Western Coal Co. (Peabody), filed in Missouri State Court in St. Louis (Cause No. 042-08561). Peabody asserts claims against the Joint Owners seeking reimbursement of royalties and other costs and breach of the coal supply agreement.

As operating agent for the project, Salt River has engaged counsel and is defending the suit on behalf of the Joint Owners. On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a Motion to remand the case to state court in St. Louis, Missouri. The Joint Owners are presently conducting discovery in connection with the Motion. NPC believes Peabody’s claims are without merit and intends to contest them.

Sierra Pacific Power Company

Farad Dam

SPPC owns 4 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. SPPC filed a claim with the 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. The insurers filed a motion for summary judgment on the coverage issue in May 2005. SPPC filed its opposition in June 2005 and the motion is currently pending before the District Court. The case is not yet set for trial. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts. Management has not recorded a loss contingency for the cost to rebuild the dam as it believes its overall exposure is insignificant.

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 have had or, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations, or cash flows.

Contract Termination Liabilities

At June 30, 2005, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” were approximately $248 million and $94 million, respectively, of charges for terminated power supply contracts and associated interest. Correspondingly, pursuant to deferred energy accounting provisions, included in NPC and SPPC deferred energy balances as of June 30, 2005, were approximately $240 million and $84 million, respectively, of charges for recovery in rates in future periods associated with the terminated power supply contracts. If NPC and SPPC are required to pay part or all of the amounts accrued, the Utilities will pursue recovery of the payments through future deferred energy filings. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amounts not permitted would be charged as a current operating expense. A significant disallowance of these costs by the PUCN could have a material effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Regulatory Contingencies

Nevada Power Company

Mohave Generation Station

NPC’s ownership interest in Mohave comprises approximately 10% of NPC’s peak generation capacity. SCE is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE’s share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Tribes. This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE’s application states that it appears that it probably will not be possible for SCE to extend Mohave’s operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave’s operations are extended past 2005. See the Environmental section above for further discussion on Mohave’s environmental issue.

Because of the coal and water supply issues at Mohave, NPC is preparing for the shutdown of the facility by the end of 2005. NPC’s Integrated Resource Plan (IRP) accepted by the PUCN in November 2003, assumes the Plant will be unavailable after December 31, 2005. In addition, in its General Rate Case filed on October 1, 2003, NPC requested that the PUCN authorize a higher depreciation rate be applied to Mohave in order to recover the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN. While the PUCN did not approve higher depreciation rates, they did authorize the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its

shutdown with recovery of any accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave in rates.

If the coal and water supply issues at Mohave are ultimately resolved, the owners, including NPC, would still be required to install the pollution control equipment, as discussed in the Environmental section, to operate the generating facility. The installation of this equipment would still require the temporary shutdown of the facility. Furthermore, the owners, including NPC, are evaluating the use of alternative fuels to operate the Mohave generating facility in the event the coal and water supply issues are not resolved. The use of alternative fuels would also cause the facility to be shutdown temporarily. NPC would seek recovery of any future costs to bring the facility into operation through a future rate case. Due to these factors, there is uncertainty as to whether Mohave will operate post December 31, 2005.

In the event Mohave is permanently shutdown, NPC will have to evaluate the plant in accordance with SFAS No. 90, “Accounting for Abandonments and Disallowances of Plant Costs” (SFAS 90). If NPC is prohibited from continued recovery of Mohave in the future, the asset may be deemed impaired under SFAS 90. If the asset is deemed impaired there could be a material effect on NPC’s and SPR’s financial position, results of operations, and future cash inflows. As of June 30, 2005, the net book value of Mohave is approximately $36.6 million.

Clark Generating Station

NPC has requested approval to retire and recover the associated retirement and cost of removal costs for the Clark Generating Station units 1, 2 and 3 (Clark Station). NPC requested approval to defer the expense by setting up regulatory asset accounts to capture the Clark retirement and cost of removal costs for future ratemaking treatment. In the event the PUCN authorizes the shut down of the Clark station and it is ultimately shut down, NPC will have to evaluate the plant in accordance with SFAS No. 90, “Accounting for Abandonments and Disallowances of Plant Costs.” If NPC elects to retire the station and is prohibited from continued recovery of Clark station in the future, the asset may be deemed impaired under SFAS 90. If the asset is deemed impaired there could be a material effect on NPC’s and SPR’s financial position, results of operations and future cash inflows. As of June 30, 2005 the net book value of Clark station is approximately $19.4 million.

NOTE 8. 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, the non-employee director stock plan and dividend participation rights associated with the convertible debt. Due to net losses for the six months ended June 30, 2005 and 2004, as well as the three month period ended June 30, 2004, these items were anti-dilutive. Accordingly, diluted EPS for these periods are computed using the weighted average shares outstanding before dilution.

SPR currently has outstanding $300 million in 7.25% convertible notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments on a 1:1 basis for dividends paid to common shareholders without exercising the conversion option. These Convertible Notes meet the criteria of a participating security in the calculation of basic EPS, and are convertible at the option of the holders into 65,749,110 common shares. See the 2004 10-K, Note 7, Long-Term Debt, for Discussion of the Convertible Notes.

Emerging Issues Task Force, Participating Securities and the Two-Class Method under FASB Statement No. 128, (EITF 03-6) requires using the “two-class” method to record the effect of participating securities in the computation of basic EPS, and the “if-converted” method in the computation of diluted EPS, if the effect is dilutive. SPR adopted EITF 03-6 for financial statements issued after June 30, 2004. The “two-class’ method was used to calculate basic EPS for the three months ended June 30, 2005. The “if-converted” method was not used to calculate diluted EPS for this period due to its anti-dilutive effect.

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


	Three Months					Six Months
	Ended June 30,					Ended June 30,
	2005		2004			2005			2004
Basic EPS
Numerator ($000)
Income / (loss) from continuing operations	$	10,025	$	(40,942	)	$	1,509		$	(83,742	)
Income / (loss) from discontinued operations	$	1	$	(2,967	)	$	6		$	(3,642	)

Earnings / (deficit) applicable to common stock	$	5,805	$	(44,884	)	$	(435	)	$	(89,334	)
Earnings applicable to convertible notes	$	3,246		—			—			—
Earnings / (deficit) used for basic calculation	$	9,051	$	(44,884	)	$	(435	)	$	(89,334	)


Denominator
Weighted average number of common shares outstanding		117,589,043		117,279,506			117,569,589			117,259,726
Shares from conversion of notes		65,749,110		—			—			—
		183,338,153		117,279,506			117,569,589			117,259,726


Earnings (Deficit) Per Share Amounts
Income / (loss) from continuing operations	$	0.05	$	(0.35	)	$	0.01		$	(0.71	)
Income / (loss) from discontinued operations⁽²⁾	$	0.00	$	(0.03	)	$	0.00		$	(0.03	)

Earnings / (deficit) applicable to common stock ⁽²⁾	$	0.05	$	(0.38	)	$	0.00		$	(0.76	)
Earnings applicable to convertible notes	$	0.05	$	—		$	—		$	—

Diluted EPS
Numerator ($000)
Income / (loss) from continuing operations	$	10,025	$	(40,942	)	$	1,509		$	(83,742	)
Income / (loss) from discontinued operations	$	1	$	(2,967	)	$	6		$	(3,642	)

Earnings / (deficit) applicable to common stock	$	9,051	$	(44,884	)	$	(435	)	$	(89,334	)

Denominator⁽¹⁾
Weighted average number of shares outstanding before dilution		117,589,043		117,279,506			117,569,589			117,259,726
Stock options		39,455		—			—			—
Executive long term incentive plan — restricted shares		345,551		—			—			—
Non-Employee Director stock plan		32,872		—			—			—
Employee stock purchase plan		5,781		—			—			—
Convertible Stock		65,749,110		—			—			—
		183,761,812		117,279,506			117,569,589			117,259,726


Earnings (Deficit) Per Share Amounts
Income / (loss) continuing operations	$	0.05	$	(0.35	)	$	0.01		$	(0.71	)
Income / (loss) from discontinued operations⁽²⁾	$	0.00	$	(0.03	)	$	0.00		$	(0.03	)

Earnings / (deficit) applicable to common stock⁽²⁾	$	0.05	$	(0.38	)	$	0.00		$	(0.76	)


1)		The denominator used for diluted EPS calculation does not include stock equivalents for stock options, restricted and performance shares issued under executive long-term incentive plan options under the non-employee Director stock plan and employee stock purchase plan, for periods ending June 30, 2005 and 2004, due to their anti-dilutive effect. The amounts for periods ending June 30, 2005 and 2004 that would be included in the calculation would be 412,041 and 185,882 shares, respectively.

		The denominator also does not include stock equivalents resulting from the conversion of SPR’s PIES and options issued under the Nonqualified stock option plan for periods ending June 30, 2005 and 2004, due to conversion prices being higher than market prices for all periods. The amounts that would be included in the calculation, if the conversion and exercise prices were met, would be 17.3 million shares for SPR’s PIES for both periods, and 1.1 million and 1.3 million shares for options under the Nonqualified stock option plan for the periods ending June 30, 2005 and 2004, respectively.


2)		Due to rounding to the nearest cent amounts less than $.01 are indicated by zero.

NOTE 9. GOODWILL AND OTHER MERGER COSTS

SPR’s Consolidated Balance Sheet as of June 30, 2005 included approximately $4 million of goodwill assigned to SPR’s unregulated operations and approximately $19 million of goodwill assigned to SPPC’s regulated gas business. The goodwill assigned to the regulated gas business is subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulations”, which permits SPPC to capitalize certain costs that may be recovered through rates. SPPC expects to demonstrate in its next general rate case for the gas distribution business that savings from the merger allocable to the gas business exceed goodwill and other merger costs and, as a result, to recover goodwill and merger costs through future gas rates. Accordingly, management has not reviewed goodwill assigned to the gas business for impairment. If the PUCN were to disallow any portion of the $19 million of goodwill assigned to SPPC’s gas business, that portion would be subject to impairment testing under the provisions of SFAS No. 142, “Accounting for Goodwill, Other Intangible Assets” (SFAS No. 142).

The approximate $4 million of goodwill assigned to SPR’s unregulated operations were subject to impairment review under the provisions of SFAS No. 142. SFAS No. 142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was developed for SPR’s unregulated businesses (TGPC and LOS) to determine the fair value of each reporting unit as of March 31, 2005. As a result, goodwill assigned to TGPC and LOS was determined not to be impaired.

NOTE 10. PENSION AND OTHER POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other postretirement costs for the three and six months ended June 30, 2005 and 2004 follows. This summary is based on a September 30 measurement date (dollars in thousands):


	Three Months Ended June 30,												Six Months Ended June 30,
	2005			2004			2005			2004			2005			2004			2005			2004

							Other Postretirement												Other Postretirement
	Pension Benefits						Benefits						Pension Benefits						Benefits
Service cost	$	4,620		$	4,497		$	820		$	779		$	9,241		$	8,994		$	1,641		$	1,559
Interest cost		8,062			7,568			2,465			2,382			16,124			15,137			4,929			4,764
Expected return on plan assets		(9,042	)		(7,658	)		(903	)		(1,034	)		(18,083	)		(15,316	)		(1,805	)		(2,067	)
Amortization of prior service cost		428			428			16			16			857			857			32			32
Amortization of Transition Obligation		—			—			242			242			—			—			485			485
Amortization of net (gain)/loss		1,614			2,243			1,059			1,157			3,227			4,486			2,118			2,313


Net periodic benefit cost	$	5,682		$	7,078		$	3,699		$	3,542		$	11,366		$	14,158		$	7,400		$	7,086

As disclosed in Note 12, Retirement Plan and Post-retirement Benefits, of the combined SPR, NPC, and SPPC Annual Report 10-K, as of December 31, 2004, there is no employer contribution expected in 2005 for pension benefits. The amount previously disclosed for other postretirement benefits was $0.2 million; however, the employer contribution is now expected to be $15 million due to actuarial projections that show a favorable outcome for the plan year as a result of the additional funding. During the six months ended June 30, 2005, approximately $5 million was paid toward the employer contribution.

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)		unseasonable weather and other natural phenomena, which, in addition to impacting NPC’s and SPPC’s (the “Utilities”) customers’ demand for power, can have potentially serious impacts on the Utilities’ ability to procure adequate supplies of fuel or purchased power to serve their respective customers and on the cost of procuring such supplies;

	(2)		whether the Utilities will be able to continue to obtain fuel, power and natural gas from their suppliers on favorable payment terms, particularly in the event of unanticipated power demands (for example, due to unseasonably hot weather), sharp increases in the prices for fuel, power and/or natural gas, or a ratings downgrade;

	(3)		whether the Utilities will be successful in obtaining the Public Utilities Commission of Nevada (the “PUCN”) approval to recover the outstanding balance of their other regulatory assets and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

	(4)		a requirement to pay Enron Power Marketing, Inc. (Enron) for amounts allegedly due under terminated purchase power contracts;

	(5)		unfavorable rulings in rate cases filed and 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 recorded by SPPC for its gas distribution business;

	(6)		the ability of SPR, NPC and SPPC to maintain access to the capital markets to support their requirements for working capital, including amounts necessary to finance deferred energy costs, construction costs, and acquisition costs, particularly in the event of additional unfavorable rulings by the PUCN, a downgrade of the current debt ratings of SPR, NPC, or SPPC and/or adverse developments with respect to the Utilities’ pending litigation with power and fuel suppliers;

	(7)		whether the Utilities will be able to continue to pay SPR dividends under the terms of their respective financing and credit agreements, the Enron Bankruptcy Court’s order, their regulatory order from the PUCN, limitations imposed by the Federal Power Act and, in the case of SPPC, under the terms of SPPC’s restated articles of incorporation;

	(8)		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;

	(9)		the final outcome of SPPC’s pending lawsuit in Nevada state court seeking to reverse the PUCN’s 2004 decision on SPPC’s 2003 General Rate case disallowing the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project;

	(10)		the final outcome of NPC’s pending lawsuit in Nevada state court seeking to reverse portions of the PUCN’s 2002 order denying the recovery of NPC’s deferred energy costs;

	(11)		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;

	(12)		industrial, commercial, and residential growth in the service territories of the Utilities;

	(13)		the financial decline of any significant customers;

	(14)		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;

	(15)		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;

	(16)		changes in environmental regulations laws or regulation, including the imposition of significant new limits on mercury and other emissions from coal-fired power plants;

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

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

	(19)		financial market conditions, including changes in availability of capital or interest rate fluctuations;

	(20)		unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs; and

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

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 for 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 and the Utilities collectively), and includes the following for each of SPR, NPC and SPPC:

	•		Results of Operations

	•		Analysis of Cash Flows

	•		Liquidity and Capital Resources

	•		Regulatory Proceedings (Utilities)

	•		Recent Pronouncements

SPR’s Utilities operate three regulated business segments: NPC electric, SPPC electric and SPPC natural gas service. Both Utilities provide electric service, and SPPC provides natural gas service. 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 accordingly, 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 intends to continue to focus on improving earnings and operating cash flows, controlling costs and reducing debt while working to restore an investment grade credit rating.

The population growth within the Utilities’ service territory has been and is projected to continue at a rapid rate. The population growth has been driven by economic expansion throughout the state, with the gaming industry in Las Vegas being the most significant component.

The Utilities are exposed to a variety of risks inherent in their commercial operations, including risks from energy supply, credit, facilities, information and control systems, environmental, and accidental loss. The Utilities address these risks in a variety of ways. Energy risk is addressed through commitments to build or obtain generation, transmission and energy supply contracts. These commitments are subject to the approval of the Public Utilities Commission of Nevada (PUCN), in some cases the Federal Energy Regulatory Commission (FERC), and, additionally for SPPC, the California Public Utility Commission (CPUC) through resource planning regulations. Other multi-year risks are addressed, in part, through insurance policies as well as the Utilities’ strategic planning processes. Shorter-term risks are also addressed through insurance and through annual budgets, key performance indicators and prioritized objectives.

In addition to customer growth, loads and resulting revenues are affected by weather, rate changes, and customer usage patterns. Energy sales by the Utilities fluctuate primarily as a result of seasonal weather conditions. 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 also typically occurs in the summer, but has a winter peak nearly as high as the summer peak. Therefore, the Utilities’ operating revenues and associated expenses are not generated or incurred evenly throughout the year.

NPC’s revenues for the six months ended June 30, 2005 increased from the same period in 2004 primarily as a result of customer growth. This increase was partially offset by an energy rate decrease that went into effect April 1, 2005. NPC’s net income for the six months ended June 30, 2005 increased compared to the same period in 2004, primarily as a result of increased revenues, partially offset by higher operating expenses and interest charges.

SPPC’s electric and gas revenues for the six months ended June 30, 2005 increased compared to the same period in 2004 primarily as a result of increased customer rates and growth. SPPC’s net income for the six months ended June 30, 2005 increased compared to the same period in 2004 primarily as a result of increased revenues and the disallowance of a portion of SPPC’s costs associated with Pinon Pine recorded in the second quarter of 2004.

SPR’s net income from continuing operations for the six months ended June 30, 2005 increased compared to the same period in 2004 as a result of items recorded in the second quarter of 2004 that did not recur in 2005. These items were the write-off of goodwill associated with the 1999 merger of SPR and NPC, disallowed merger costs, tender fees paid in connection with extinguishment of certain debt and the disallowance of a portion of SPPC’s costs associated with Pinon Pine.

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. In February 2005, the PUCN approved a settlement agreed to by all parties in NPC’s deferred energy case initially filed in November 2004. The settlement resolved all issues in the case and resulted in no disallowances. SPPC filed for recovery of its deferred energy costs in January 2005. In May 2005, the PUCN issued its order granting recovery of $27.1 million of the $27.7 million of deferred expenses requested. The Utilities are required to file for annual rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every two years to adjust general rates that include its cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. SPPC

is scheduled to file a gas and electric general rate case in October 2005. The Utilities remain committed to maintaining a positive relationship with our regulators for the benefit of all stakeholders.

Significant Business Issues

While SPR and the Utilities have addressed many issues that were facing us in past years, we continue to face a number of key business issues, including, among other things: the ongoing litigation involving Enron, improving our debt profile, managing of our energy risk, and pursuing strategic initiatives to reduce our reliance on external power supplies. Details relating to the discussion below can be found in the 2004 10-K Notes to the Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Enron Litigation

Currently, the Utilities are involved in five court cases and hearings involving Enron Power Marketing, Inc (Enron) enumerated as follows: U.S. Bankruptcy Court for the Southern District Court of New York (Bankruptcy Court), U.S. District Court for the Southern District of New York (U.S. District Court); FERC hearings consisting of the FERC Early Termination, FERC Revocation Show Cause Proceeding and the FERC Gaming and Show Cause Proceeding. See details of the court cases and hearings in Note 7, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Based on the U.S. District Court’s decision, the Utilities reversed the accrued interest included in contract termination liabilities by approximately $40 million for the year ended 2004. Although the Judgment entered by the Bankruptcy Court has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron will remain in place through the pendency of all remands and appeals of the Judgment. If the Utilities are ultimately required to pay part or all of the amounts accrued, the Utilities will pursue recovery of the payments through future deferred energy filing. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amount not permitted would be charged as a current operating expense.

A trial date had initially been set for July 11, 2005 before the Bankruptcy Court but the trial date has been changed to November 7, 2005. A description of the legal proceedings leading up to the U.S. District Court’s order to vacate along with a discussion of all pending matters related to the Enron litigation are detailed in Note 7, Commitments and Contingencies of the Condensed Notes to Financial Statements.

On August 8, 2005, President Bush signed the Domenici Barton Energy Policy Act into law (the “Energy Bill”). The Energy Bill contains language that relates to the Utilities' disputes with Enron over termination payments Enron claims are owed to them arising from forward power purchase contracts terminated by Enron in 2002. The amendment grants FERC exclusive jurisdiction over the determination of whether any such payments are unjust, unreasonable or contrary to the public interest. The Utilities have not yet determined what impact the law will have on the status of the various ongoing legal proceedings at this time.

Improved Debt Profile

In 2005, management has sought and continues to seek opportunities to refinance existing debt at lower interest rates and to extend the maturity dates of certain indebtedness in order to obtain interest cost savings and to better manage SPR’s and the Utilities’ indebtedness profiles.

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of its $300 million outstanding 7.25% Convertible Notes (Notes) due 2010 to convert their Notes to shares of SPR common stock. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” an approximate $54 million cash payment will be expensed during the third quarter of 2005 which SPR expects to pay using the proceeds from long-term debt financing. The amount of SPR common shares that would be issued if all the outstanding Notes are converted is 65,749,110 shares with an approximate $248 million increase to equity equal to the current carrying value of the Notes. Details of conversion offer are discussed later under SPR Liquidity and Capital Resources.

On June 20, 2005, SPR issued and sold $140,860,000 of its Series A Floating Rate Senior Notes, due November 16, 2005, and $99,140,000 of its Series B Floating Rate Senior Notes, due November 16, 2005 (the “Floating Rate Notes”). $230,500,000 of the proceeds from this issuance were used to make an equity contribution to NPC as detailed in Note 4, Short-Term Borrowings of the Condensed Notes to Financial Statements.

In May 2005, SPR completed a tender offer to exchange $99,142,000 of its existing Premium Income Equity Securities (“Old PIES”) for new Premium Income Equity Securities (“New PIES”). The amount exchanged equaled approximately 41% of the Old PIES securities. The Senior Notes associated with the New PIES were remarketed on June 14, 2005 at a rate of 7.803%, reduced from the 7.93% rate of the Senior Notes associated with the Old PIES. The remarketed Senior Notes will mature on June 15, 2012. Details of the PIES transaction are discussed later under SPR Liquidity and Capital Resources.

In a continuing effort to improve NPC’s debt profile, on July 14, 2005 upon receipt of the equity contribution from SPR, discussed above, NPC redeemed $87,500,000 aggregate principal amount of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, and $122,500,000 aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013, in accordance with the redemption provisions of these securities. These redemptions constituted 35% of the principal amounts outstanding of each of the Series E and Series G Notes.

These transactions are among those that are being executed in order to lead the companies toward achieving investment grade status.

Management of Energy Risk

The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. The Utilities’ significant need to tap energy markets is necessary because the Utilities’ ownership and contractual call on power generating assets is insufficient to meet our customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk — the prospect that energy supplies will not be sufficient to fulfill customer requirements.

The Utilities systematically manage and control each of the energy-related risks through three primary vehicles – organization and governance, energy risk management programs, and energy risk control practices.

The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.

The Utilities follow an approved energy supply plan that governs the purchase and sale of fuel and wholesale power and the associated transmission or transportation services in order to mitigate these risks. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for hedging in conjunction with energy purchases and sales are also used to mitigate these risks.

Strategic Initiatives to Reduce Reliance on External Power Supplies

In 2004, the Utilities announced a strategy to continue reducing their exposure to volatile swings in power prices by investing in additional generating facilities.

In October 2004, after PUCN approval, NPC purchased a partially constructed nominally rated 1,200 MW (megawatts) natural gas-fired combined cycle power plant from Duke Energy. NPC was able to finance the Chuck Lenzie Generating Station (Lenzie) project at lower rates than were forecast during the PUCN’s approval process. In addition, the PUCN approved an incentive return on equity (ROE) equal to 2% above the authorized ROE on construction costs of the facility, plus an additional 1% incentive for early completion and production. NPC entered into a contract with Fluor Enterprises to complete construction of the Lenzie project. The revised completion of Unit 1 of the facility is targeted for December 2005 and March 2006 is the targeted completion date for Unit 2. Total costs to acquire and complete construction of the facility are estimated at approximately $545 million, which includes $182 million paid to Duke for the facility.

NPC announced on June 21, 2005 that it has signed an agreement to acquire from Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy Corporation (“PWEC”), a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC (“GenWest”), a 75 percent ownership interest in the Silverhawk Power Plant (“Silverhawk”). Silverhawk is a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles northeast of Las Vegas. The purchase price of Silverhawk is approximately $208 million, subject to certain closing adjustments. The acquisition is subject

to approval by the PUCN, the FERC and the Department of Justice through a Hart-Scott-Rodino filing. NPC currently plans to fund the acquisition of Silverhawk utilizing debt.

SPPC received PUCN approval of the Integrated Resource Plan to move forward with permitting and conceptual engineering to build a 500-megawatt, natural gas-fired, combined cycle electric generating plant at the Tracy plant site (“Tracy”), east of Reno. There will be an assessment of coal-fired generation alternatives for the Valmy Generating Station, including expansion and possible construction of a future generating unit.

Nevada 2005 Legislative Session Impacts

The 2005 Nevada Legislative Session and 22^nd Special Session ended on June 7, 2005. The Legislature passed several bills that will affect the Utilities’.

Senate Bill 238 requires a natural gas utility to request approval from the PUCN to adjust its rates on a quarterly basis between annual rate adjustment applications based on changes in the costs of natural gas.

Senate Bill 256 establishes a specific schedule for electric utilities to file general and deferred rate applications. SPPC is to file a general rate case on or before October 3, 2005, and at least once every 24 months thereafter. NPC is to file a general rate case on or before November 15, 2006, and at least once every 24 months thereafter. In addition, the filing dates for the annual deferred rate cases have been changed to December 1, 2005 for SPPC and January 17, 2006 for NPC. This bill also allows the PUCN 210 days to render a decision on rate cases.

Assembly Bill 3 revises the provisions governing the portfolio standard for renewable energy and energy from a qualified energy recovery process. The portfolio standard requires each provider to generate, acquire or save electricity from portfolio energy systems or efficiency measures in an amount that is not less than 20% by calendar year 2015, which represents an increase from 15% under the current standard. Additionally, AB 3 allows a provider of electric service to receive one portfolio energy credit for each kilowatt-hour of electricity that the provider generates, acquires or saves from a portfolio energy system or efficiency measure.

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 $39.2 million and $49.6 million of interest costs for the six months ended June 30, 2005 and 2004, respectively.

During the three months ended June 30, 2005, SPR had earnings applicable to common stock of approximately $9.1 million compared to an approximate $44.9 million deficit applicable to common stock for the same period in 2004. The change in SPR’s consolidated results for the three months ended June 30, 2005 compared to the same period in 2004 was primarily due to the following charges recorded during the three months ended June 30, 2004 (before income taxes):

	•		A charge of approximately $9.8 million during the second quarter of 2004 of interest expense costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8 ³/4% Senior Unsecured Notes due 2005; and

	•		A charge of approximately $47 million recorded during the second quarter of 2004 as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Pinon Pine.

During the six months ended June 30, 2005, SPR incurred a deficit applicable to common stock of approximately $435 thousand compared to an approximate $89.3 million deficit applicable to common stock for the same period in 2004. The

decrease in SPR’s consolidated loss during the six months ended June 30, 2005 compared to the same period in 2004 was primarily due to the following charges recorded during the six months ended June 30, 2004 (before income taxes):

	•		a non-cash goodwill impairment charge of approximately $11.7 million;

	•		a non-cash charge to write-off disallowed merger costs of approximately $5.9 million; and

	•		a charge of approximately $23.7 million of tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8³/4% Senior Unsecured Notes due 2005.

	•		a charge of approximately $47 million as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Pinon Pine.

See the 2004 10-K for additional discussion of the above items.

As of August 5, 2005, NPC had paid $25.3 million in dividends to SPR and declared an additional dividend of approximately $1.8 million. As of August 5, 2005, SPPC declared dividends of $19.8 million to SPR. As of August 5, 2005, SPPC paid approximately $2.0 million in dividends and declared an additional $975 thousand in dividends to holders of its preferred stock.

ANALYSIS OF CASH FLOWS

SPR’s consolidated net cash flows increased for the six months ended June 30, 2005 compared to the same period in 2004, primarily as a result of an increase in cash from operating and financing activities offset by an increase in cash used in investing activities. Cash flows for operating activities are higher in 2005 due to rate increases that became effective in the second quarter of 2004, which was the result of the Utilities’ General and Deferred Energy Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash from operating activities was the $60 million escrow payment for Enron in 2004, and a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facilities. The increase in cash used by investing activities was mainly due to construction at NPC for the Chuck Lenzie project. The increase in cash from financing activities in 2005, when compared to 2004, was primarily due to the issuance of short term borrowings of $240 million at SPR and the $50 million draw on NPC’s revolving credit facility in 2005, and the repayment of $25 million in short-term borrowings in March 2004.

LIQUIDITY AND CAPITAL RESOURCES

SPR, on a stand-alone basis, had cash and cash equivalents of approximately $239.3 million at June 30, 2005, which does not include restricted cash and investments of approximately $10.9 million representing collateral for payment of interest up to and including the August 14, 2005 payment in connection with SPR’s 7.25% Convertible Notes due 2010. This balance reflects the receipt of proceeds from the private placement of $240 million of short-term floating rate senior notes. On July 13, 2005, SPR made a capital contribution of $230.5 million to Nevada Power Company. SPR expects to repay its short-term floating rate senior notes with the $240 million of proceeds it will receive on November 15, 2005 from the settlement of the common stock purchase contracts associated with its old PIES and new PIES. Given the current balance of 4,804,350 PIES outstanding, approximately 17,344,184 SPR common shares are expected to be issued at the settlement date of November 15, 2005.

SPR paid approximately $36.8 million of debt service obligations on its existing debt securities during the six months ended June 30, 2005. Included in these payments was approximately $10.9 million previously provided for at the time the Convertible Notes were issued as discussed above. Excluding interest on SPR’s 7.25% Convertible Notes, SPR has approximately $26.4 million payable of debt service obligations remaining during 2005, which SPR expects to meet through the payment of dividends by the Utilities to SPR.

In the second quarter of 2005, SPR entered into certain financing transactions discussed below. There were no other material changes to contractual obligations as set forth in SPR’s 2004 10-K during the three months and six months ended June 30, 2005.

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. The specific agreements entered into by the Utilities, restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are discussed in detail in the 2004 10-K, Note 9, Dividend Restrictions of the Notes to Financial Statements, and remain unchanged from their description in the 2004 10-K.

As of June 30, 2005, each Utility was able to pay dividends, subject to a cap, under the most restrictive test in its financing agreements; however, the total amount of dividends that the Utilities can pay to SPR under their financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under their financing agreements is greater than the amount that the Utilities can pay under their other dividend restrictions. The Utilities have agreed, under the terms of a stipulation with Enron, that they will not pay dividends to SPR other than for SPR’s debt service obligations and current operating expenses, which amount (discussed above) is substantially less than the maximum amounts the Utilities can pay as dividends under their financing agreement dividend restrictions. As of August 5, 2005, NPC had paid $25.3 million in dividends to SPR and declared an additional dividend of approximately $1.8 million. As of August 5, 2005, SPPC declared dividends of $19.8 million to SPR. As of August 5, 2005, SPPC paid approximately $2.0 million in dividends and declared an additional $975 thousand in dividends to holders of its preferred stock.

Financing Transactions (SPR — Holding Company)

On June 20, 2005, SPR issued and sold $140,860,000 of its Series A Floating Rate Senior Notes, due November 16, 2005, and $99,140,000 of its Series B Floating Rate Senior Notes, due November 16, 2005 (the “Floating Rate Notes”). The Series A Floating Rate Notes will bear interest at a rate equal to 3-month LIBOR plus 2.00%, and the Series B Floating Rate Notes will bear interest at a rate equal to 3-month LIBOR plus 1.00%. The Floating Rate Notes were issued to Qualified Institutional Buyers under Rule 144A. Of the proceeds from this issuance $230.5 million was used to make an equity contribution to NPC and the balance will be used for general corporate purposes. NPC used the equity contribution to redeem approximately $210 million of General and Refunding Mortgage Notes. See Note 5, Long-Term Debt for further discussion on the redemption by NPC.

SPR may redeem, at any time, all or a part of the Floating Rate Notes, without premium or penalty, upon not less than three, nor more than thirty, days’ notice. Subject to certain limitations, additional Floating Rate Notes may be issued from time to time; provided, however, that the aggregate principal amount of Floating Rate Notes outstanding at any time may not exceed $240,000,000.

Each of SPR’s short-term floating rate notes and the remarketed new PIES senior notes due June 15, 2012 limit SPR’s ability to make certain payments (including dividends on common stock, payments on subordinated indebtedness, certain investments and other payments in respect of any equity interests of SPR); provided, however, that SPR may make such payments if:

	•		there are no defaults or events of default with respect to the Floating Rate Notes or the Senior Notes, as applicable,

	•		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 2.0 to 1, and

	•		the total amount of such payments is less than:

	•		the sum of 50% of SPR’s consolidated net income measured on a quarterly basis cumulative of all quarters from April 1, 2004, plus

	•		100% of SPR’s aggregate net cash proceeds from contributions to its common equity capital or the issuance or sale of certain equity or convertible debt securities of SPR, plus

	•		the lesser of cash return of capital or the initial amount of certain restricted investments, plus

	•		the fair market value of SPR’s investment in certain subsidiaries.

The terms of the short-term floating rate notes and the remarketed new PIES senior notes also permit SPR to make payments in excess of the amounts described above in an aggregate amount not to exceed $50 million from the date of the issuance of the applicable series of senior notes.

In addition, the terms of the short-term floating rate notes and the remarketed new PIES senior notes restrict SPR and its restricted subsidiaries from incurring any additional indebtedness 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 2.0 to 1, or

	•		the debt incurred is specifically permitted under the terms of the applicable series of senior notes, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, certain letters of credit issued to support SPR’s obligations with respect to energy suppliers, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan, as amended, or Sierra Pacific Power Company’s 2004 Integrated Resource Plan, as amended, and additional indebtedness not to exceed $75 million at any time outstanding.

Among other things, the short-term floating rate notes and the remarketed new PIES senior notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. There are also limitations on certain fundamental structural changes to SPR and limitations on the disposition of property. In the event of a change of control of SPR, the holders of the applicable series of senior notes and the remarketed new PIES senior notes are entitled to require that SPR repurchase their applicable senior notes for a cash payment equal to 100% of the aggregate principal amount plus accrued and unpaid interest.

If the short-term floating rate notes and the remarketed new PIES senior notes are upgraded to investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Rating Group, Inc., certain restrictions applicable to such notes, including the covenants related to restricted payments, the incurrence of indebtedness and issuance of preferred stock, dividend and other payment restrictions affecting restricted subsidiaries, the designation of restricted and unrestricted subsidiaries, transactions with affiliates and restrictions on business activities, will be suspended and will no longer be in effect so long as such notes remain investment grade.

Additional covenants applicable to SPR’s short-term floating rate notes and remarketed new PIES senior notes are discussed below.

SPR expects to repay its short-term floating rate senior notes with the $240 million of proceeds it will receive on November 15, 2005 from the settlement of the common stock purchase contracts associated with its old PIES and new PIES. Given the current balance of 4,804,350 PIES outstanding, approximately 17,344,184 SPR common shares are expected to be issued at the settlement date of November 15, 2005.

Limitations on Indebtedness

The terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014, $99.1 million 7.803% Senior Notes due June 15, 2012, $140.9 million Series A Floating Rate Senior Notes due November 16, 2005 and $99.1 million Series B Floating Rate Senior Notes due November 16, 2005, restrict SPR and any of its Restricted Subsidiaries (NPC and SPPC) from incurring any additional indebtedness unless:

1. 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, or

2. the debt incurred is specifically permitted under the terms of the applicable series of notes, which permit the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit supporting SPR’s or any Restricted Subsidiary’s obligations to energy suppliers, or

3. the indebtedness is incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan and SPPC’s 2004 Integrated Resource Plan.

If the applicable series of notes are 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. As of June 30, 2005, SPR, NPC and SPPC would have been able to issue approximately $592 million of additional indebtedness on a consolidated basis, assuming an interest rate of 7.00 %, per the requirement stated in number 1 above.

Cross Default Provisions

None of the Utilities’ financing agreements contain a cross-default provision that would result in an event of default by that Utility upon an event of default by 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. The primary cross-default provisions in SPR’s and the Utilities’ various financing agreements are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Resources – Liquidity and Capital Resources (SPR Consolidated),” SPR’s short-term floating rate notes and remarketed new PIES senior notes provide for an event of default if SPR or either of the Utilities fails to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable for so long as SPR’s 7.25% Convertible Notes are outstanding.

Judgment Related Defaults

Certain of the Utilities’ financing agreements contain judgment default provisions that provide for an event of default if a final, unstayed judgment is rendered against the Utility and remains undischarged after 60 days. The judgment default provisions in the Utilities’ various financing agreements and the consequences of a judgment default for either of the Utilities are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Resources — Liquidity and Capital Resources (SPR Consolidated).” There have been no changes to the Utilities’ judgment default provisions as described in the 2004 10-K. The terms of SPR’s senior notes including its 8 5/8% Senior Unsecured Notes due 2014, 7.25% Convertible Notes due 2010, short-term floating rate senior notes and remarketed new PIES senior notes provide for a default in the event that SPR or either of the Utilities fails to pay a final judgment in excess of $10 million or more for a period of 60 days.

Effect of Holding Company Structure

As of June 30, 2005, SPR (on a stand-alone basis) has a substantial amount of outstanding debt and other obligations including, but not limited to: $141 million of its unsecured 7.93% Senior Notes due 2007; $99 million of its unsecured 7.803% Senior Notes due 2012; $240 million of short-term floating rate Senior Notes, due November 16, 2005; $300 million of its 7 1/4% Convertible Notes due 2010; and $335 million of its unsecured 8 5/8% 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 and preferred stockholders. 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, guarantee holders, NPC’s preferred trust security holders, and SPPC’s preferred stockholders.

As of June 30, 2005, SPR, NPC, SPPC, and their subsidiaries had approximately $4.4 billion of debt and other obligations outstanding, consisting of approximately $2.3 billion of debt at NPC, approximately $1 billion of debt at SPPC and approximately $1.1 billion of debt at the holding company and other subsidiaries. Additionally, SPPC had $50 million of outstanding preferred stock. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2005, NPC recognized net income of approximately $21 million compared to $13.6 million for the same period in 2004. During the six months ended June 30, 2005, NPC recognized net income of approximately $12.9 million compared to a net loss of approximately $1.8 million for the same period in 2004. NPC paid a common stock dividend of $ 25.3 million to SPR during the six months ended June 30, 2005 and declared a dividend of approximately $1.8 million on August 2, 2005.

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


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Operating Revenues:
Electric	$	451,384	$	449,925		0.3	%	$	805,518	$	776,458		3.7	%

Energy Costs:
Purchased power		228,254		191,508		19.2	%		369,682		319,039		15.9	%
Fuel for power generation		53,212		60,312		-11.8	%		108,852		109,667		-0.7	%
Deferral of energy costs-disallowed		—		—					—		1,586		-100.0	%
Deferral of energy costs-electric-net		8,111		38,808		-79.1	%		43,934		82,126		-46.5	%

		289,577		290,628		-0.4	%		522,468		512,418		2.0	%


Gross Margin
Electric	$	161,807	$	159,297		1.6	%	$	283,050	$	264,040		7.2	%

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

Electric Operating Revenues


					Change							Change
	Three Months				from			Six Months				from
	Ended June 30,				Prior Year			Ended June 30,				Prior
	2005		2004		%			2005		2004		Year %
Electric Operating Revenues:
Residential	$	193,300	$	190,643		1.4	%	$	336,305	$	319,131		5.4	%
Commercial		98,490		97,811		0.7	%		181,245		173,066		4.7	%
Industrial		137,293		135,929		1.0	%		240,624		230,327		4.5	%

Retail revenues		429,083		424,383		1.1	%		758,174		722,524		4.9	%
Other¹		22,301		25,542		-12.7	%		47,344		53,934		-12.2	%

Total Revenues	$	451,384	$	449,925		0.3	%	$	805,518	$	776,458		3.7	%


Retail sales in thousands of megawatt-hours (MWH)		4,814		4,727		1.8	%		8,602		8,488		1.3	%

Average retail revenue per MWH	$	89.13	$	89.78		-0.7	%	$	88.14	$	85.12		3.5	%


¹		Primarily wholesale, as discussed below.

Nevada Power retail revenues were higher for the three months ended June 30, 2005, as compared to the same period in the prior year due to customer growth. The number of residential, commercial, and industrial customers increased by 5.7%, 5.6%, and 1.7%, respectively. These increases were slightly offset by an energy rate decrease of .6% overall which resulted from NPC’s Deferred Energy Rate Case effective April 1, 2005 (refer to Regulatory Proceedings).

Retail revenues were higher for the six months ended June 30, 2005, as compared to the same period in 2004, due to customer growth and higher energy rates. The number of residential, commercial, and industrial customers increased by 5.6%, 5.7%, and 3.2%, respectively. Higher energy rates became effective April 1, 2004, which were the result of NPC’s General and Deferred Energy Rate Cases (refer to Regulatory Proceedings in the 2004 10-K). These increases were slightly offset by an overall decrease of .6% resulting from NPC’s Deferred Energy Rate Case effective April 1, 2005 and by cooler weather in 2005.

Based on NPC’s projected customer forecast, NPC expects retail electric customers in the Clark County area to continue to grow. NPC has requested a Base Tariff Energy Rate increase starting on October 1, 2005, of which the final outcome is yet to be determined.

Electric Operating Revenues – Other decreased for the three months and six months ended June 30, 2005 compared to the same periods in 2004, primarily due to a decrease in sales volumes for wholesale electric power to other utilities and certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power. Partially offsetting this decrease was a refund in 2004 of $5.9 million owed to transmission customers as a result of FERC’s approval of a tariff agreement on July 8, 2004 (refer to Regulatory Proceedings in the 2004 10-K), which decreased revenues in 2004. The tariff agreement also lowered the transmission rates which contributed to the decrease in 2005 revenues.

Purchased Power


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Purchased Power	$	228,254	$	191,508		19.2	%	$	369,682	$	319,039		15.9	%

Purchased Power in thousands of MWhs		3,457		3,137		10.2	%		5,697		5,498		3.6	%
Average cost per MWh of Purchased Power	$	66.03	$	61.05		8.2	%	$	64.89	$	58.03		11.8	%

NPC’s purchased power costs increased for the three months ended June 30, 2005, compared to the same period in 2004, due to higher prices and increased volume. NPC’s energy contracts calculate prices using gas indexes. Therefore, higher natural gas prices in 2005 increased the price of purchased power. Additionally, NPC satisfied more of its load requirements through purchased power rather than generation.

NPC’s purchased power costs increased for the six months ended June 30, 2005, compared to the same period in 2004, primarily due to higher prices and volumes as discussed above. Furthermore, in the first quarter of 2005, compared to the same time period in 2004, purchased power costs were higher primarily due to two gas tolling agreements entered into during the second quarter of 2004. These gas tolling agreements are purchased power agreements where NPC provides natural gas to the supplier who generates the energy for NPC. The gas tolling agreements are based on gas indexes, therefore, the increase in natural gas prices increased the cost of purchased power.

Fuel for Power Generation


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Fuel for Power Generation	$	53,212	$	60,312		-11.8	%	$	108,852	$	109,667		-0.7	%

Thousands of MWhs generated		1,849		2,144		-13.8	%		3,735		3,932		-5.0	%
Average cost per MWh of Generated Power	$	28.78	$	28.13		2.3	%	$	29.14	$	27.89		4.5	%

Fuel for power generation decreased for the three and six months ended June 30, 2005 compared to the same period in 2004 due to a decrease in volume. The decrease in volume was primarily due to NPC satisfying more of its native load requirements through purchased power rather than generation as a result of the increase of natural gas costs. The increase in the average unit fuel cost per megawatt-hour was due to higher natural gas prices.

Deferred Energy Costs — Net


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change
					from							Change
					Prior							from Prior
	2005		2004		Year %			2005		2004		Year %
Deferred energy costs disallowed	$	—	$	—		N/A		$	—	$	1,586		N/A
Deferred energy costs — net	$	8,111	$	38,808		-79.1	%	$	43,934	$	82,126		-46.5	%

Deferred energy costs disallowed for the six months ended June 30, 2004, consisted of the write-off of $1.6 million of deferred energy costs incurred during the twelve months ended September 30, 2003, that were disallowed by the PUCN in

NPC’s 2003 deferred energy rate case in March 2004. See, Regulatory, NPC’s 2003 Deferred Energy Rate Case in the 2004 10-K.

Deferral of energy costs — net decreased for the three months and six months ended June 30, 2005 compared to the same periods in 2004 due to the decrease in amortization as a result of lower unamortized deferred energy balances and a decrease in the amortization rate. This was offset somewhat by actual fuel and purchased power costs exceeding revenues to a lesser extent in 2005. During periods when actual fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as a reduction in costs.

See “Critical Accounting Policies” and Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in the 2004 10-K for more information regarding deferred energy accounting.

Allowance for Funds Used During Construction (AFUDC)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
					Change						Change
					from						from
					Prior						Prior
	2005		2004		Year %		2005		2004		Year %

Allowance for other funds used during construction	$	4,408	$	625		N/A	$	7,898	$	1,282		N/A

Allowance for borrowed funds used during construction	$	5,479	$	776		N/A	$	9,792	$	1,706		N/A

	$	9,887	$	1,401		N/A	$	17,690	$	2,988		N/A

NPC’s AFUDC is higher for the three months and six months ended June 30, 2005 compared to the same periods in 2004 due to an increase in Construction Work in Progress (CWIP). The increase is primarily due to the purchase of the partially completed Chuck Lenzie Generation Plant in October 2004 and associated construction costs.

Other (Income) and Expenses


	Three Months									Six Months
	Ended June 30,									Ended June 30,
							Change									Change
							from									from
							Prior									Prior
	2005			2004			Year %			2005			2004			Year %

Other operating expense	$	49,112		$	50,913			-3.5	%	$	100,211		$	90,635			10.6	%
Maintenance expense	$	16,397		$	16,790			-2.3	%	$	33,352		$	36,746			-9.2	%
Depreciation and amortization	$	30,761		$	29,991			2.6	%	$	61,163		$	58,730			4.1	%
Income tax expense/(benefit)	$	4,756		$	5,339			-10.9	%	$	(2,038	)	$	(6,114	)		-66.7	%
Interest charges on long-term debt	$	41,613		$	37,683			10.4	%	$	83,142		$	74,834			11.1	%
Interest charges-other	$	4,239		$	5,241			-19.1	%	$	8,571		$	9,828			-12.8	%
Interest accrued on deferred energy	$	(4,216	)	$	(4,798	)		-12.1	%	$	(8,741	)	$	(10,193	)		-14.2	%
Disallowed merger costs	$	—		$	—			N/A		$	—		$	3,961			N/A
Other income	$	(5,449	)	$	(5,389	)		1.1	%	$	(12,362	)	$	(11,129	)		11.1	%
Other expense	$	1,817		$	1,487			22.2	%	$	3,393		$	2,928			15.9	%
Income taxes — other income and expense	$	4,945		$	3,057			61.8	%	$	8,047		$	5,045			59.5	%

Other operating expense for the three month period ending June 30, 2005 was comparable to the same period in the prior year. The increase in Other operating expense for the six month period ending June 30, 2005 compared to the same period in 2004 was primarily due to increased advisory fees, amortization of regulatory assets and severance costs associated with the reorganization of NPC, SPPC and SPR.

Maintenance expense for the three month period ending June 30, 2005 was comparable to the same period in the prior year. The decrease in Maintenance expense for the six month period ending June 30, 2005 compared to the same period in the prior year is due to the timing of scheduled and unscheduled plant maintenance at Clark Station, Sunrise, Reid Gardner and Mohave during 2004.

NPC’s Income tax expense for the three months ended June 30, 2005 is comparable to the same period in 2004. NPC’s income tax benefit for the six months ended June 30, 2005 decreased compared to the same period in 2004 as a result of an increase in the pretax net income.

Interest charges on Long-Term Debt increased for the three months and six months ended June 30, 2005 compared to the same period in 2004 due to higher debt balances during the three months and six months ended June 30, 2005. See Note 7, Long-Term Debt of the Notes to Consolidated Financial Statements in the 2004 10-K and Note 5, Long-Term Debt for additional information regarding long-term debt.

Interest charges-other decreased for the three months and six months ended June 30, 2005 compared to the same period in 2004 due to a reduction in fees for short-term financing.

Interest accrued on deferred energy costs decreased for the three months and six months ended June 30, 2005 compared to the same period 2004 primarily due to lower deferred fuel and purchased power balances during 2005.

NPC did not incur any disallowed merger costs for the six months ended June 30, 2005, nor does NPC expect to incur any disallowed merger costs in the remainder of 2005. Disallowed merger costs for the six months ended June 30, 2004 were a result of the PUCN decision in NPC’s 2003 General Rate Case. Disallowed merger costs expense includes the write-off of costs that resulted from the July 28, 1999 merger between SPR and NPC which were determined to be not recoverable through rates in the March 26, 2004, PUCN decision on NPC’s 2003 general rate case. The PUCN decision permitted substantially all of the merger costs that NPC requested recovery of except for a 20% reduction in merger costs that were to be amortized over the next two years. Also included in the write-off are merger costs allocable to non-Nevada jurisdictional sales that NPC has determined will not be recovered in rates. See “Regulatory Proceedings” — in the 2004 10-K.

NPC’s Other income increased for the three months and six months ended June 30, 2005, compared to the same period in 2004 due to increased interest income from temporary investments and continuing amortization of gains from the disposition of non-utility property.

NPC’s Other expense for the three and six months ended June 30, 2005 increased from the same periods in 2004 due to higher lobbying activities and the reclassification of costs associated with NPC’s Supplementary Executive Retirement Plan. These increases were partially offset by a decrease in corporate advertising.

Income Taxes-Other Income and Expense increased for the three months and six months ended June 30, 2005 compared to the same periods in 2004 due to an increase in other non-operating income.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during the six months ended June 30, 2005, compared to the same period in 2004, primarily as a result of an increase in cash used for investing activities offset by increases in cash flows from operating and financing activities. Cash used in investing activities increased mainly due to an increase in utility construction for the Chuck Lenzie project under construction in 2005. The increase in cash from operating activities is primarily due to rate increases that became effective in the second quarter of 2004, as a result of NPC’s General and Deferred Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash from operating activities was the $50 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility. Cash from financing activities increased due to the draw of $50 million on NPC’s revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

NPC had cash and cash equivalents of approximately $72.7 million at June 30, 2005, and additional liquidity in the amount of $244.6 million available under the company’s $350 million revolving credit facility. The total liquidity does not include restricted cash of $49 million which has been deposited into escrow in connection with the stay of the Enron Judgment. As of August 5, 2005, NPC has $100 million of direct borrowings and $65.1 million of letters of credit under the revolving credit facility.

NPC anticipates it will be able to meet fuel and purchased power costs through internally generated funds, including the recovery of deferred energy and if necessary the use of its revolving credit facility. As discussed in Construction Expenditures and Financing and Contractual Obligations in the 2004 10-K, NPC anticipates capital requirements for construction costs in 2005 will be approximately $629.8 million, which NPC expects to finance with internally generated funds and if necessary the use of its revolving credit facility. As of June 30, 2005, NPC has incurred approximately $286.8 million in construction expenditures.

On June 21, 2005, Nevada Power Company entered into an agreement with GenWest LLC, a wholly owned subsidiary of Pinnacle West Capital Corporation, to acquire its 75% ownership of the Silverhawk Power Station. NPC has filed a financing application with the PUCN to issue new debt in connection with the Silverhawk acquisition. (See Regulatory Actions) There were no other material changes to contractual obligations as set forth in NPC’s 2004 10-K during the three months and six months ended June 30, 2005.

Financing Transactions

Mortgage Indentures

NPC’s Indenture of Mortgage, dated as of October 1, 1953, between NPC and Deutsche Bank Trust Company Americas (the “First Mortgage Indenture”), creates a first priority lien on substantially all of NPC’s properties. As of June 30, 2005, $372.5 million of NPC’s first mortgage bonds were outstanding. In connection with the issuance of its Series E, Series G and Series I Notes, NPC agreed that it would not issue any more first mortgage bonds.

NPC’s First Mortgage Indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock. In February 2004, NPC amended this restriction in its First Mortgage Indenture to:

	1.		change the starting point for the measurement of cumulative net earnings available for the payment of dividends on NPC’s capital stock from March 31, 1953 to July 28, 1999 (the date of NPC’s merger with SPR), and

	2.		permit NPC to include in its calculation of proceeds available for dividends and other distributions the capital contributions made to NPC by SPR.

NPC does not anticipate that the First Mortgage Indenture dividend restriction as amended, will materially limit the amount of dividends that it may pay to SPR in the foreseeable future.

NPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of NPC’s properties in Nevada that is junior to the lien of the first mortgage indenture. As of June 30, 2005, $1.3 billion of NPC’s General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

	1.		70% of net utility property additions,

	2.		the principal amount of retired General and Refunding Mortgage Bonds, and/or

	3.		the principal amount of first mortgage bonds retired after October 19, 2001.

On the basis of (1), (2) and (3) above and on plant accounting records as of June 30, 2005 (which do not include additions to plant associated with the acquisition of the Lenzie Generating Station), NPC had the capacity to issue approximately $349 million of additional General and Refunding Mortgage securities. This amount does not include $210 million of capacity made available by the redemption of $87,500,000 aggregate principal amount of the Series E notes and $122,500,000 aggregate principal amount of the Series G notes on July 14, 2005 (see NPC Financing Transactions).

Although NPC has substantial capacity to issue additional General and Refunding Mortgage securities on the basis of property additions and retired securities, the financial covenants contained in the Series E, Series G, Series I, and Series L Notes, the Series H Bond and the Revolving Credit Facility limit the amount of additional indebtedness that NPC may issue and the reasons for which such indebtedness may be issued.

NPC also has the ability to release property from the liens of the two mortgage indentures 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.

Limitations on Indebtedness

Certain of NPC’s financing agreements contain restrictions on NPC’s ability to issue additional indebtedness. The restrictions on issuing additional indebtedness in NPC’s various financing agreements are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Nevada Power Company — Liquidity and Capital Resources.” Under the terms of the limitations on issuing additional indebtedness, which remain unchanged from their description in the 2004 10-K, NPC would have been able to issue additional indebtedness. In addition, the terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014, $99.1 million 7.803% Senior Notes due June 15, 2012, $140.9 million Series A Floating Rate Senior Notes due November 16, 2005 and $99.1 million Series B Floating Rate Senior Notes due November 16, 2005, contain restrictions on SPR’s, NPC’s and SPPC’s ability to issue additional indebtedness. As of June 30, 2005, SPR, NPC and SPPC are restricted to issuing no more than approximately $592 million of additional indebtedness on a consolidated basis, assuming an interest rate of 8 5/8% based upon SPR’s most recent debt issuance, unless the indebtedness being issued is specifically permitted under the terms of SPR’s 8 5/8% Senior Notes due 2014. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Resources — Liquidity and Capital Resources (SPR Consolidated) — Limitations on Indebtedness” for a description of the applicable restrictions.

Financial Covenants

NPC’s Credit Agreement 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 June 30, 2005, NPC was in compliance with both of the financial maintenance covenants.

Cross Default Provisions

NPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by NPC upon an event of default by SPR or SPPC under any of their respective financing agreements. 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 other indebtedness) 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. The primary cross-default provisions in NPC’s various financing agreements are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Nevada Power Company — Liquidity and Capital Resources,” and remain unchanged from their description in the 2004 10-K.

Judgment Related Defaults

Certain of NPC’s financing agreements contain judgment default provisions that provide for an event of default if a final, unstayed judgment is rendered against NPC and remains undischarged after 60 days. The judgment default provisions in NPC’s various financing agreements and the consequences of a judgment default for NPC are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Nevada Power Company — Liquidity and Capital Resources.” There have been no changes to NPC’s judgment default provisions as described in the 2004 10-K.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2005, SPPC recognized net income of approximately $4.9 million compared to a net loss of approximately $32.2 million for the same period in 2004. During the six months ended June 30, 2005, SPPC recognized net income of approximately $17 million compared to a net loss of approximately $24.5 million for the same period in 2004. During the six months ended June 30, 2005, SPPC declared and paid approximately $2.0 million dividends to holders of its preferred stock. On August 2, 2005, SPPC declared an additional $975 thousand in dividends to holders of its preferred stock and declared $19.8 million of dividends on its common stock, all of which is held by its parent, SPR.

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 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.

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


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from								Change from
	2005		2004		Prior Year %			2005		2004			Prior Year %
Operating Revenues:
Electric	$	217,199	$	202,425		7.3	%	$	444,209	$	404,266			9.9	%
Gas		32,136		21,879		46.9	%		99,674		81,355			22.5	%

	$	249,335	$	224,304		11.2	%	$	543,883	$	485,621			12.0	%


Energy Costs:
Purchased Power	$	70,365	$	71,758		-1.9	%	$	149,089	$	137,718			8.3	%
Fuel for Power generation		54,626		53,797		1.5	%		108,988		107,599			1.3	%
Deferral of energy costs-electric-net		5,530		134		N/A			9,823		4,705			108.8	%
Gas purchased for resale		23,024		14,482		59.0	%		76,504		62,399			22.6	%
Deferral of energy costs-gas-net		1,332		1,376		-3.2	%		1,004		(31	)		N/A

	$	154,877	$	141,547		9.4	%	$	345,408	$	312,390			10.6	%


Energy Costs by Segment:
Electric	$	130,521	$	125,689		3.8	%	$	267,900	$	250,022			7.2	%
Gas		24,356		15,858		53.6	%		77,508		62,368			24.3	%

	$	154,877	$	141,547		9.4	%	$	345,408	$	312,390			10.6	%


Gross Margin by Segment:
Electric	$	86,678	$	76,736		13.0	%	$	176,309	$	154,244			14.3	%
Gas		7,780		6,021		29.2	%		22,166		18,987			16.7	%

	$	94,458	$	82,757		14.1	%	$	198,475	$	173,231			14.6	%

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 Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2005		2004		year %			2005		2004		year %
Electric Operating Revenues:
Residential	$	58,559	$	49,676		17.9	%	$	132,132	$	112,636		17.3	%
Commercial		75,724		70,036		8.1	%		148,267		134,909		9.9	%
Industrial		77,302		70,568		9.5	%		150,638		137,124		9.9	%

Retail		211,585		190,280		11.2	%		431,037		384,669		12.1	%
Other¹		5,614		12,145		-53.7	%		13,172		19,597		-32.8	%

Total Revenues	$	217,199	$	202,425		7.3	%	$	444,209	$	404,266		9.9	%

Retail sales in thousands of MWh		2,177		2,180		-0.1	%		4,472		4,413		1.34	%

Average retail revenue per MWh	$	97.19	$	87.28		11.4	%	$	96.39	$	87.17		10.6	%


¹		Primarily wholesale, as discussed below.

SPPC’s retail revenues increased for the three months and six months ended June 30, 2005 as compared to the same periods in the prior year due to increases in customer rates, and customer growth, partially offset by cooler temperatures. Nevada customer rates increased as a result of SPPC’s General Rate Case, effective June 1, 2004, and an increase in Nevada customer energy rates as a result of SPPC’s Deferred Energy Cases effective July 15, 2004 and June 1, 2005. California customer energy rates increased effective December 1, 2004 (refer to “Regulatory Proceedings”). Also contributing to the increase was the growth in residential and commercial customers (3.1% and 3.7%, respectively).

The decrease in Electric Operating Revenues — Other for the three and six months ended June 30, 2005 compared to the same periods in 2004, was primarily due to a decrease in the sales volumes for wholesale electric power to other utilities. Also contributing to the decrease was certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power under.

Gas Operating Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2005		2004		year %			2005		2004		year %
Gas Operating Revenues:
Residential	$	16,575	$	10,692		55.0	%	$	54,094	$	42,078		28.6	%
Commercial		7,857		5,888		33.4	%		26,477		21,520		23.0	%
Industrial		3,399		2,222		53.0	%		9,122		6,268		45.5	%

Retail revenue		27,831		18,802		48.0	%		89,693		69,866		28.4	%
Wholesale revenue		3,588		2,389		50.2	%		8,608		10,001		-13.9	%
Miscellaneous		717		688		4.2	%		1,373		1,488		-7.7	%

Total Revenues	$	32,136	$	21,879		46.9	%	$	99,674	$	81,355		22.5	%


Retail sales in thousands of decatherms		2,753		1,926		42.9	%		9,152		7,487		22.2	%

Average retail revenues per decatherm	$	10.11	$	9.76		3.6	%	$	9.80	$	9.33		5.0	%

Retail gas revenues increased for the three months and six months ended June 30, 2005 primarily due to cooler temperatures in 2005 as compared to the same periods of 2004. Also contributing to this increase was an increase in energy related rates that became effective November 1, 2004. This increase in the retail rates was the result of SPPC’s Purchased Gas Adjustment filing (see “Regulatory Proceedings” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2004 10-K). Also influencing this increase is the growth of retail customers of 4.5%.

The wholesale revenues for the three months ended June 30, 2005 increased compared to the same period in 2004, primarily due to mild weather in June, which resulted in an increase in the availability of gas for wholesale sales. The decrease in wholesale revenues for the six months ended June 30, 2005 as compared to the same period in 2004 was due to the increase in retail usage in the first five months of 2005 as discussed above which decreased the availability of gas for wholesale sales.

Based on SPPC’s projected customer forecast, SPPC expects retail gas customers to continue to grow.

Purchased Power


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Purchased Power	$	70,365	$	71,758		-1.9	%	$	149,089	$	137,718		8.3	%

Purchased Power in thousands of MWhs		1,432		1,429		0.2	%		2,832		2,633		7.6	%
Average cost per MW of Purchased Power	$	49.13	$	50.22		-2.2	%	$	52.64	$	52.30		1.0	%

Purchased power costs for the three months ended June 30, 2005 decreased slightly due to the effect of certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power. Purchased power costs for the six months ended June 30, 2005 compared to the same period in 2004 increased primarily due to higher volumes and higher prices of purchased power. The increase in volume was the result of SPPC relying more on purchased power to satisfy its native load requirements.

Fuel For Power Generation


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Fuel for Power Generation	$	54,626	$	53,797		1.5	%	$	108,988	$	107,599		1.3	%

Thousands of MWh generated		1,018		1,060		-4.0	%		2,089		2,243		-6.9	%
Average fuel cost per MWh of Generated Power	$	53.66	$	50.75		5.7	%	$	52.17	$	47.97		8.8	%

Fuel for power generation costs increased for the three months and six months ended June 30, 2005 as compared to the same period in 2004 primarily due to higher natural gas and coal prices. The decrease in the volume of generation was due to SPPC relying more on purchased power to satisfy its native load requirements.

Gas Purchased for Resale


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Gas Purchased for Resale	$	23,024	$	14,482		59.0	%	$	76,504	$	62,399		22.6	%

Gas Purchased for Resale (in thousands of decatherms)		3,028		1,980		52.9	%		10,387		9,210		12.8	%
Average cost per decatherm	$	7.60	$	7.31		4.0	%	$	7.37	$	6.78		8.7	%

The cost of gas purchased for resale increased for the three months and six months ended June 30, 2005 as compared to the same period in 2004 primarily due to increases in natural gas prices and the volume of gas purchased for resale. The volume of gas purchased for resale increased for the three and six months ended June 30, 2005 as compared to the same period in 2004 primarily due to the colder winter weather continuing through May of 2005.

Deferred Energy Costs


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change								Change
					from Prior								from Prior
	2005		2004		Year %			2005		2004			Year %
Deferred energy costs — electric — net	$	5,530	$	134		N/A		$	9,823	$	4,705			N/A
Deferred energy costs — gas — net	$	1,332	$	1,376		-3.2	%	$	1,004	$	(31	)		N/A

	$	6,862	$	1,510		N/A		$	10,827	$	4,674			N/A

The increase in deferred energy costs — electric — net for the three months and six months ended June 30, 2005, compared to the same period in 2004, was due to actual fuel and purchased power costs exceeding recovery of fuel and purchased power costs through current rates at a lesser extent in 2005 than in 2004. During periods when actual fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as a reduction in costs.

SPPC’s Deferred energy costs — gas — net decreased for the three months ended June 30, 2005, as the result of lower amortization of prior deferred energy costs in 2005 as compared with 2004 due to lower rates. This was offset by an increase in the recovery of actual natural gas costs through rates in 2005 compared to the recovery of costs through rates in 2004. SPPC’s Deferred energy costs — gas — net increased for the six months ended June 30, 2005, as a result of an increase in the recovery of actual natural gas costs through rates in 2005 compared to the recovery of gas costs through rates in 2004. This was partially offset by a decrease in amortization of prior deferred energy costs in 2005 as compared with 2004 due to lower rates.

Allowance for Funds Used During Construction (AFUDC)


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from							from
					Prior							Prior
	2005		2004		Year %			2005		2004		Year %
Allowance for other funds used during construction	$	481	$	567		-15.2	%	$	800	$	1,283		-37.6	%
Allowance for borrowed funds used during construction	$	449	$	891		-49.6	%	$	739	$	2,134		-65.4	%

	$	930	$	1,458		-36.2	%	$	1,539	$	3,417		-55.0	%

SPPC’s AFUDC is lower for the three months and six months ended June 30, 2005 compared to the same periods in 2004 due to the completion of the Falcon to Gonder transmission line, which was placed in service in May 2004.

Other (Income) and Expense


	Three Months									Six Months
	Ended June 30,									Ended June 30,
							Change									Change
							from									from
							Prior									Prior
	2005			2004			Year %			2005			2004			Year %
Other operating expense	$	33,769		$	32,891			2.7	%	$	68,538		$	63,702			7.6	%
Maintenance expense	$	7,760		$	5,426			43.0	%	$	13,751		$	10,358			32.8	%
Depreciation and amortization	$	22,537		$	22,138			1.8	%	$	44,924		$	43,336			3.7	%
Income tax expense/(benefit)	$	2,751		$	(571	)		N/A		$	9,354		$	305			N/A
Interest charges on long-term debt	$	17,319		$	17,847			-3.0	%	$	34,626		$	36,715			-5.7	%
Interest charges—other	$	1,255		$	2,470			N/A		$	2,401		$	4,627			-48.1	%
Interest accrued on deferred energy	$	(1,693	)	$	(1,183	)		43.1	%	$	(3,276	)	$	(2,337	)		40.2	%
Other income	$	(1,496	)	$	(896	)		67.0	%	$	(2,467	)	$	(1,756	)		40.5	%
Disallowed merger costs	$	—		$	—			N/A		$	—		$	1,929			N/A
Plant costs disallowed	$	—		$	47,092			N/A		$	—		$	47,092			N/A
Other expense	$	1,593		$	1,242			28.3	%	$	3,233		$	2,555			26.5	%
Income taxes — other income and expense	$	763		$	(15,035	)		N/A		$	1,215		$	(15,358	)		N/A
Taxes other than income	$	5,931		$	4,981			19.1	%	$	10,679		$	9,996			6.8	%

Other operating expense increased for the three month and six month periods ending June 30, 2005 compared to the same period in 2004 primarily due to increased legal fees, amortization of regulatory assets and severance costs associated with the reorganization of SPPC, NPC and SPR.

Maintenance costs for the three and six month periods ending June 30, 2005 increased from the prior year due to the timing of scheduled and unscheduled plant maintenance at Ft. Churchill, Valmy and Tracy.

Depreciation and amortization expenses were higher for the three months and the six months ended June 30, 2005 compared to the same periods in 2004 primarily as a result of increases to plant-in-service. The major contributor to this increase was the addition of the Falcon to Gonder transmission line, which was placed in service May 2004.

SPPC’s Income tax expense for the three months and six months ended June 30, 2005, increased compared to the same period in 2004, as a result of an increase in pretax net income.

SPPC’s interest charges on long-term debt for the three months and six months ended June 30, 2005 decreased from the same period in 2004 due to lower rates of interest on new and existing debt. See Note 7, Long-Term Debt of the Notes to Financial Statements in the 2004 10-K and Note 5, Long-Term Debt for additional information regarding long-term debt.

SPPC’s interest charges-other for the three months and six months ended June 30, 2005 decreased compared to the same period in 2004 due primarily to the absence of charges related to the accounts receivable facility and short-term debt. See Note 6, Short-Term Borrowings, of the Notes to Financial Statements in the 2004 10-K for additional information.

Interest accrued on deferred energy costs increased for the three months and six months ended June 30, 2005 compared to the same period in 2004 due to higher deferred fuel and purchased power balances and rates during 2005.

SPPC’s Other income for the three months and six months ended June 30, 2005 increased primarily due to increased interest income.

SPPC did not incur any disallowed merger costs for the six months ended June 30, 2005, nor does SPPC expect to incur any disallowed merger costs in 2005. Disallowed merger costs for the six months ended June 30, 2004 was a result of the PUCN decision in SPPC’s 2004 General Rate Case. Disallowed merger costs expense includes the 2004 write-off of costs that resulted from the July 28, 1999 merger between SPR and NPC, allocable to non-Nevada jurisdictional electricity sales, which were determined not to be recoverable in future rates. See “Regulatory Proceedings” — in the 2004 10-K.

SPPC’s plant costs disallowed for the three months ended and six months ended June 30, 2004 was the result of the decision of the PUCN to disallow recovery of a portion of the costs associated with the Pinon Pine power plant project. See the 2004 10-K, Note 3, Regulatory Actions for further discussion.

SPPC’s Other expense increased for the three months and six months ended June 30, 2005 compared to the same period in 2004, due to various charges, all of which were not individually significant.

Income taxes — other income and expense recorded income tax expense for the three months and six months ended June 30, 2005 compared to an income tax benefit recognized during the same period in 2004. The 2004 tax benefit was recognized primarily as a result of an impairment charge associated with the Pinon Pine generating facility during the second quarter of 2004. See Note 3, Regulatory Actions in the 2004 10-K for additional information regarding the impairment charge.

The increase in taxes other than income for the three months and six months ended June 30, 2005, compared to the same periods in 2004 were caused by the settlement of a sales tax audit during the second quarter and an increase in franchise fees based on net income.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows increased during the six months ended June 30, 2005, when compared to the same period in 2004, as a result of an increase in cash flows from operating activities and a decrease in cash used by financing activities partially offset by an increase in cash used in investing activities. Cash flows from operating activities were higher in 2005 due to rate increases that became effective in the second quarter of 2004, which was the result of SPPC’s General and Deferred Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash flow from operations was the $11 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility and changes in accounts receivables for tax sharing agreements. Cash flows used by financing activities decreased in 2005, when compared to 2004, due to the repayment of $25 million in short-term borrowing in March 2004. Cash flows used in investing activities increased primarily as a result of construction activity related to growth.

LIQUIDITY AND CAPITAL RESOURCES

SPPC had cash and cash equivalents of approximately $81 million at June 30, 2005, and additional liquidity in the amount of $72.5 million available under the company’s $75 million revolving credit facility. On October 20, 2005, the maximum availability under SPPC’s revolving credit facility will be reduced to $50 million. The total liquidity does not include restricted cash of $11 million which has been deposited into escrow in connection with the stay of the Enron Judgment. As of August 8, 2005, SPPC has no direct borrowings and $2.9 million of letters of credit outstanding under the revolving credit facility.

SPPC anticipates it will be able to meet fuel and purchased power costs through internally generated funds, including the recovery of deferred energy. As discussed in Construction Expenditures and Financing and Contractual Obligations in the 2004 10-K, SPPC anticipates capital requirements for construction costs during 2005 totaling approximately $176.6 million, which SPPC expects to finance with internally generated funds and, if necessary, the use of its revolving credit facility. As of June 30, 2005, SPPC has incurred approximately $48.7 million in construction expenditures.

During the three months and six months ended June 30, 2005, there were no material changes to contractual obligations as set forth in SPPC’s 2004 10-K.

Mortgage Indentures

SPPC’s First Mortgage Indenture creates a first priority lien on substantially all of SPPC’s properties in Nevada and California. As of June 30, 2005, $487.3 million of SPPC’s first mortgage bonds were outstanding. SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds.

SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s properties in Nevada that is junior to the lien of the first mortgage indenture. As of June 30, 2005, there were $420 million of SPPC’s General and Refunding Mortgage securities outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

	1.		70% of net utility property additions,

	2.		the principal amount of retired General and Refunding Mortgage Bonds, and/or

	3.		the principal amount of first mortgage bonds retired after April 8, 2002.

On the basis of (1), (2) and (3) above, as of June 30, 2005, SPPC had the capacity to issue approximately $360 million of additional General and Refunding Mortgage securities. Although SPPC has substantial capacity to issue additional General and Refunding Mortgage securities on the basis of property additions and retired securities, the financial covenants contained in the Revolving Credit Agreement limit the amount of additional indebtedness that SPPC may issue and the reasons for which such indebtedness may be issued.

SPPC also has the ability to release property from the liens of the two mortgage indentures 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 bonds issuable under that indenture.

Limitations on Indebtedness

Certain of SPPC’s financing agreements contain restrictions on SPPC’s ability to issue additional indebtedness. The restrictions on issuing additional indebtedness in SPPC’s various financing agreements are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Power Company — Liquidity and Capital Resources.” Under the terms of the limitations on issuing additional indebtedness, which remain unchanged from their description in the 2004 10-K, SPPC would have been able to issue additional indebtedness. In addition, the terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014, $99.1 million 7.803% Senior Notes due June 15, 2012, $140.9 million Series A Floating Rate Senior Notes due November 16, 2005 and $99.1 million Series B Floating Rate Senior Notes due November 16, 2005, contain restrictions on SPR’s, NPC’s and SPPC’s ability to issue additional indebtedness. As of June 30, 2005, SPR, NPC and SPPC are restricted to issuing no more than approximately $592 million of additional indebtedness on a consolidated basis, assuming an interest rate of 8 5/8% based upon SPR’s most recent debt issuance, unless the indebtedness being issued is specifically permitted under the terms of SPR’s 8 5/8% Senior Notes due 2014. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Resources — Liquidity and Capital Resources (SPR Consolidated) — Limitations on Indebtedness” for a description of the applicable restrictions.

Financial Covenants

SPPC’s Credit Agreement 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 June 30, 2005, SPPC was in compliance with both of the financial maintenance covenants.

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 other indebtedness) 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. The primary cross-default provisions in SPPC’s various financing agreements are briefly summarized in the 2004 10-K

in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Power Company — Liquidity and Capital Resources,” and remain unchanged from their description in the 2004 10-K.

Judgment Related Defaults

Certain of SPPC’s financing agreements contain judgment default provisions that provide for an event of default if a final, unstayed judgment is rendered against SPPC and remains undischarged after 60 days. The judgment default provisions in SPPC’s various financing agreements and the consequences of a judgment default for SPPC are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sierra Pacific Power Company — Liquidity and Capital Resources.” There have been no changes to SPPC’s judgment default provisions as described in the 2004 10-K.

REGULATORY PROCEEDINGS (UTILITIES)

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the 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 and TGPC 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 following regulatory proceedings have affected, or are expected to affect the Utilities’ financial positions, results of operations and cash flows.

Nevada Matters

Nevada Power Company 2004 Deferred Energy Case

The application also requested an increase to the going-forward base tariff energy rate (BTER).

Nevada Power Company Updated Going Forward Base Tariff Energy Rate (BTER)

On June 3, 2005, pursuant to newly adopted regulations allowing more frequent energy cost adjustments, NPC filed a request to increase its BTER tariff’s to reflect forecasted energy costs. The requested increase to the BTER is expected to increase revenue by $62.4 million for the period November 1, 2005 to October 31, 2006, which would reduce deferred energy expenses during the same period. The proposed increase will not affect NPC’s operating income. The increase is intended to recoup, on a more current basis, actual fuel and purchased power costs that NPC will incur during the rate effective period.

The request represents an increase of 3.74% for the average residential customer and 3.53% for all other customer classes. NPC requested the new rates to become effective on October 1, 2005.

The PUCN has scheduled a hearing for late August 2005 and has scheduled a decision for September 21, 2005.

Nevada Power Company Amendments to its Integrated Resource Plan

Long Term Power Exchange

On May 19, 2005, the PUCN approved the Power Exchange Agreement.

Silverhawk Plant Acquisition

On June 29, 2005, NPC filed an application for approval to purchase a 75% interest in the 560MW gas fired Silverhawk power plant from Pinnacle West Capital Corp, Pinnacle West Energy Corp and GenWest, LLC. The Silverhawk generating plant is located 25 miles northeast of Las Vegas and is near to NPC’s Lenzie Power plant. NPC made concurrent filings requesting approval of an interim Silverhawk power purchase agreement and approval to issue $210 million of debt financing.

Clark Generating Unit Retirements

NPC has requested approval to retire and recover the associated retirement and cost of removal costs for the Clark Generating Station units 1, 2 and 3. NPC requested approval to defer the expense by setting up regulatory asset accounts to capture the Clark retirement and cost of removal costs for future ratemaking treatment. In the event the PUCN authorizes the shut down of the Clark station, NPC will have to evaluate the plant in accordance with SFAS No. 90, “Accounting for Abandonments and Disallowances of Plant Costs.” For further discussion see Note 7, Commitments and Contingencies, Regulatory Contingencies of the Condensed Notes to Financial Statements.

NPC asked the Commission to issue its decision before September 30, 2005. The PUCN held a pre-hearing conference on July 27, 2005 and set hearing dates for September 28-30, 2005.

Sierra Pacific Power Company 2005 Electric Deferred Energy Case

The application also requested an increase to the going-forward BTER.

On April 6, 2005, the PUCN Staff and the BCP filed written direct testimony in this case. The testimony recommended full recovery of the deferred balance after a $576 thousand reduction to reflect an accounting adjustment mutually agreed to by the parties. The PUCN Staff recommended adoption of the higher BTER rate that SPPC filed on March 30, 2005 while the BCP opposed the implementation of the higher BTER.

For further detail of deferred energy cases see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2004 10-K.

Sierra Pacific Power Company Updated Going Forward Energy Rate (BTER)

On July 1, 2005, SPPC filed a request to increase its BTER tariffs to reflect forecasted energy costs. The requested increase to the BTER is expected to increase revenue by $32.3 million for the period October 1, 2005 to September 30, 2006 and would reduce future deferred energy expenses during the same period. The proposed increase will not affect SPPC’s operating income. The increase is intended to recoup, on a more current basis, actual fuel and purchased power costs that SPPC will incur during the rate effective period.

The request represents an increase of 3.7% for the average customer and the requested effective date is October 1, 2005.

Sierra Pacific Power Company 2005 Gas Deferred Energy Rate Case and Gas BTER Filing

Newly enacted regulations require SPPC to account for gas purchases to serve its gas customers in the same manner as it does for its electric customer fuel and power purchases. On May 13, 2005, SPPC filed a gas deferred energy rate case requesting recovery of $6.9 million of deferred energy costs. The filing requests a two-year amortization of the deferred energy balance which represents a 3.2% average increase for all customers.

On July 1, 2005 SPPC filed a proposed gas BTER rate, which represents an average increase of 19.5% for all customer classes. The estimated BTER revenue will not change the Company’s operating income.

Hearings for the above two filings are expected to begin in the latter part of September 2005. SPPC expects a decision will be rendered in this docket by November 2005.

Sierra Pacific Power Company 2005 Electric and Gas General Rate Cases

In early October 2005, SPPC will be filing general rate cases for its gas and electric operations. SPPC’s last gas general rate case was filed in 1994 and the last electric general rate case was filed in 2003.

Sierra Pacific Power Company Amendment to its 2004 Integrated Resource Plan

On August 1, 2005, SPPC filed an amendment to its IRP previously approved by the PUCN on November 18, 2004. In the amendment SPPC is requesting approval to construct a 514 MW combined cycle unit at its Tracy Station located 16 miles East of Reno. The estimated cost to construct the unit is $421 million and is scheduled to be in service by June 2008. The unit will provide needed generation within the Utilities' control area to reliably serve the growing needs of Northern Nevada. SPPC has requested that the unit be designated as a Critical Facility under Nevada regulations, and as such, has requested the following cost recovery mechanisms: 1) an incentive return of 2% above the company authorized rate of return on equity and 2) include the project’s construction work in progress (CWIP) in rate base for all general rate cases prior to the facility being placed into service. SPPC is expecting a decision by the PUCN by mid-December.

Nevada Power Company/Sierra Pacific Power Company Quality of Service Investigation

In compliance with the order issued in NPC’s 2003 General Rate case, NPC and SPPC jointly filed with the PUCN, on July 1, 2004, their recommended quality of service and customer service measurements. In the filing, the Utilities outlined their proposed methodologies for measuring the quality of service and customer service measurements, pre and post merger. More specifically the companies identified the quality of service and customer service measurements to be used in a future rate case, proposed methodology for comparing pre-merger and post-merger performance, and proposed consequences and rewards for under- or over- performance in a future test year. On March 2, 2005, the Interveners in the case, the staff of the PUCN and the BCP, filed testimony regarding their proposed methodologies for measuring quality of service and customer service measurements. The Utilities filed rebuttal testimony on April 18, 2005. The hearing officer issued a draft order for comment by the parties and the PUCN. The parties filed comments and the PUCN discussed the proposed order during its July 12, 2005 agenda meeting. The PUCN is expected to vote on a revised order in the 3^rd quarter of 2005.

California Matters

Sierra Pacific Power Company

On June 3, 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue from approximately 40,000 California customers. The request represents a 12.7% average increase. The Company has requested that the new rates become effective on January 1, 2006.

FERC Matters

Sierra Pacific Power Company 2004 Transmission Rate Case

RECENT PRONOUNCEMENTS

The Securities and Exchange Commission (SEC) announced on April 14, 2005 that it was delaying implementation of SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R). Under SFAS 123R, registrants would have been required to implement the standard as of the beginning of the first interim or annual period that begins after June 15, 2005. SPR would have been permitted to follow the pre-existing accounting literature for the first and second quarters of 2005, but required to follow SFAS 123R for third quarter reports and thereafter. The SEC’s new rule allows SPR to implement SFAS 123R at the beginning of the next fiscal year that begins after June 15, 2005, or periods beginning December 31, 2005. The SEC’s new rule does not change the accounting required by SFAS 123R. Amounts that were previously shown in footnote disclosure by SPR will now be recognized in the income statement. SPR intends to utilize the services of its actuaries to value share-based compensation.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements—An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. SPR and the Utilities are currently evaluating the effect that the adoption of SFAS 154 will have on its results of operations and financial condition but does not expect it to have a material impact.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2005, 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 and preferred trust securities. 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
	2005			2006			2007			2008			2009			Thereafter			Total			Value
Long-term Debt
SPR
Fixed Rate	$	—		$	—		$	141,077		$	—		$	—		$	734,141		$	875,218		$	1,400,165
Average Interest Rate		—			—			7.93	%		—			—			7.95	%		7.97	%
NPC
Fixed Rate	$	210,008		$	15		$	17		$	13		$	162,500		$	1,741,048		$	2,113,601		$	2,238,647
Average Interest Rate		9.78	%		8.17	%		8.17	%		8.17	%		10.88	%		7.20	%		7.74	%
Variable Rate							$	50,000					$	15,000		$	100,000		$	165,000		$	165,000
Average Interest Rate								5.5	%					1.74	%		1.74	%		2.88	%
SPPC
Fixed Rate	$	854		$	52,400		$	2,400		$	322,400		$	600		$	617,250		$	995,904		$	1,026,365
Average Interest Rate		6.10	%		6.71	%		6.10	%		7.99	%		6.10	%		6.52	%		7.00	%

Total Debt	$	210,862		$	52,415		$	193,494		$	322,413		$	178,100		$	3,192,439		$	4,149,723		$	4,830,177

Commodity Price Risk

See the 2004 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, 2004.

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 $43 million as of June 30, 2005, which increased significantly from December 31, 2004 due to an increase in trading transactions to meet the demand of the summer months and a general increase in power market prices of approximately $5 — $7 per MWh. In the event that the trading counterparties are unable to deliver under their contracts, it may be necessary for the Utilities to purchase alternative energy at a higher market price.

ITEM 4. 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 June 30, 2005, the registrants’ disclosure controls and procedures were adequate and effective.

(b) Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the second quarter of 2005 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

On October 10, 2004, the U.S. District Court for the Southern District of New York (U.S. District Court) rendered a decision vacating an earlier judgment by the Bankruptcy Court (also for the Southern District of New York) against the Utilities in favor of Enron Power Marketing, Inc. (Enron), and remanded the case back to the Bankruptcy Court for fact-finding. A description of the legal proceedings leading up to the District Court’s order to vacate follows, along with a discussion of all pending matters related to the Enron litigation.

Bankruptcy Court Judgment

On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy case in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court), asserting claims for termination payments Enron claimed it was owed under purchased power contracts with the Utilities. Enron sought liquidated damages in the amount of approximately $216 million from NPC and $93 million from SPPC based on assertions by Enron that it had contractual rights under the Western Systems Power Pool Agreement (WSPPA) to terminate deliveries to the Utilities. Enron based its assertion on a claim that the Utilities did not provide adequate assurance of the Utilities’ performance under the WSPPA. The Utilities dispute that they owe the monies sought by Enron and have denied liability on numerous grounds, including termination, deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.

In response to the Judgment, the Utilities filed a motion with the Bankruptcy Court seeking a stay pending appeal of the Judgment and proposing to issue General and Refunding Mortgage Bonds as collateral to secure payment of the Judgment. On November 6, 2003, the Bankruptcy Court ruled to stay execution of the Judgment conditioned upon NPC and SPPC posting into escrow $235 million and $103 million, respectively, of General and Refunding Mortgage Bonds plus approximately $282 thousand in cash by NPC for pre-judgment interest. On December 4, 2003, NPC and SPPC complied with the order of the Bankruptcy Court by issuing NPC’s $235 million General and Refunding Mortgage Bond, Series H and SPPC’s $103 million General and Refunding Mortgage Bond, Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which lowered the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made the payments as ordered on February 10, 2004. The Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall seek a ruling from the PUCN to determine whether the cash payments into escrow triggered the Utilities’ rights to seek recovery of such amounts through the Utilities’ deferred energy rate cases.

District Court for the Southern District of New York. NPC made the agreed-upon payment on April 16, 2004, which lowered the principal amount of NPC’s General and Refunding Mortgage Bond, Series H, currently held in escrow, by a like amount.

Appeal of Bankruptcy Court Judgment to U.S. District Court

	•		whether Enron’s demand for assurances at the time of termination of its power supply contracts with NPC and SPPC was reasonable;

	•		whether the assurances offered by NPC and SPPC to Enron were “reasonably satisfactory assurances”; and

	•		whether Enron would have been able to perform all of its obligations under each of the power supply contracts at the time the contracts were terminated and following termination.

The Utilities filed a motion seeking clarification of the U.S. District Court rulings with respect to the Utilities’ affirmative defenses and counterclaim regarding: fraud by Enron, violation of the Racketeer Influence Corrupt Organizations Act (RICO), anti-trust activities carried out by Enron, the constitutional power of a bankruptcy court to enter a final judgment in a “non-core matter,” and whether the Bankruptcy Court had properly determined the interest rate applicable to pre-judgment interest. This motion did not relate to Enron’s claims against the Utilities, which the U.S. District Court addressed in its October 10, 2004 decision described above. On December 23, 2004, the U.S. District Court ruled on this motion, affirming the dismissal of the Utilities’ affirmative defenses and counterclaims on the grounds that they were barred under the filed rate doctrine. However, the U.S. District Court ruled in favor of the Utilities on the calculation of pre-judgment interest.

FERC Early Termination Case

payment profits; and (c) whether Enron should be otherwise denied the authority to collect such payments because to do so would be contrary to the public interest.

Bankruptcy Court Injunction and Order Setting Trial

After the U.S. District Court issued its October 10, 2004 ruling, Enron renewed its motion with the Bankruptcy Court seeking to enjoin the Utilities from proceeding in the FERC Early Termination Case. On December 3, 2004 the Bankruptcy Court enjoined the Utilities from further prosecution of the scheduled hearing in the FERC proceeding. The Utilities have appealed this decision and are seeking a stay of the trial in Bankruptcy Court pending the outcome of the FERC Early Termination Case. The trial was initially set for July 11, 2005, but the trial date has been changed to November 7, 2005. The Utilities are unable to predict the outcome of these proceedings at this time.

FERC Revocation Show Cause Proceeding

FERC Gaming and Partnership Show Cause Proceeding

On June 25, 2003, FERC issued orders in two separate cases involving Enron Power Marketing, Inc. (Enron), among others, and potential gaming of power markets. The first was referred to as the “Gaming Show Cause Proceeding” and the second as the “Partnership Show Cause Proceeding”. The proceedings focused on Enron’s illicit trading activity in California with a variety of counterparties. On July 21, 2004, FERC consolidated the two proceedings and expanded the scope of its inquiry. FERC announced that it was revisiting its decision not to revoke Enron’s market-based rate authority retroactively and that “Enron potentially could be required to disgorge profits for all of its wholesale power sales in the Western Interconnect for the period January 16, 1997 to June 15, 2003.” Enron has sought rehearing of this order, challenging the expanded scope of the proceeding. The Utilities have joined a coalition of other Western Parties and on August 4, 2004, sought clarification that remedies other than disgorgement might be available. On March 11, 2005, the FERC issued an order clarifying issues to be covered in the administrative trial. In that order, the FERC stated that Enron’s profits under the terminated power contracts fell within the scope of that proceeding. On July 20, 2005, the FERC issued an order in the Gaming and Partnership Show Cause Proceeding involving Enron, among others, suspending the trial schedule, including the September 7, 2005 trial date, pending FERC review of a recent settlement agreement between the California parties and Enron. The order provides that the trial in this proceeding will convene within seven weeks following FERC’s review of the proposed settlement. FERC also ordered Enron not to take any action to move forward the Bankruptcy Court proceeding, and ordered it to join in any request for postponement of any filing or action in the Bankruptcy Court proceeding. In addition, FERC ordered the remaining parties, including NPC and SPPC, to participate in settlement negotiations.

FERC 206 complaints

The Utilities are contesting the amounts paid for power actually delivered by these suppliers as well as claims made by terminating power suppliers that did not deliver power, including Enron.

On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints finding that the strict public interest standard applied to the case and that the Utilities had failed to satisfy the burden of proof required by that standard. On July 28, 2003, the Utilities filed a petition for rehearing at the FERC requesting that the FERC either reconsider or rehear the case. On November 10, 2003, the FERC reaffirmed the June 26, 2003, decision. That decision has been appealed to the United States Court of Appeals for the Ninth Circuit. Oral argument was held on December 8, 2004 and a decision is pending. The Utilities are unable to predict the outcome of this appeal at this time.

Reliant and Duke Antitrust Litigation

Nevada Power Company

Morgan Stanley Proceedings

MSCG for the approximately 1.8 million (plus interest) for power delivered prior to the termination. NPC anticipates payment in the third quarter of 2005. At this time, NPC is unable to predict the outcome or timing of the matter.

El Paso Merchant Energy

Nevada Power Company 2001 Deferred Energy Case

On November 30, 2001, NPC filed an application with the PUCN seeking recovery for purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as required by law. The application sought to establish a rate to repay accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.

On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. NPC and the Bureau of Consumer Protection (BCP) both sought individual review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal to the Nevada Supreme Court.

Supreme Court rules mandate settlement talks before a matter is set for briefing and argument. As a result of that mandatory process, NPC filed a motion with the Nevada Supreme Court seeking remand of the matter back to the PUCN to consider evidence uncovered after the PUCN’s final decision. On November 2, 2004, the Nevada Supreme Court issued an order denying the motion for remand.

A briefing schedule on the underlying appeal has since been established. A decision is expected within twelve months. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Environmental Matters

Nevada Power Company

Mohave Generation Station

Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

Southern California Edison (“SCE”) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE’s share of Mohave. On October 20, 2004, the CPUC issued a proposed decision which, among other things, directed SCE to continue negotiations with the Tribes regarding post-2005 coal and water supply, and directed SCE to conduct a study of potential alternatives to Mohave.

Because coal and water supplies necessary for long-term operation of Mohave have yet to be secured, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave’s operations are extended past 2005. Due to the lack of resolution of these coal and water supply issues with the tribes, it is not the intention of Southern California Edison (SCE) and other owners to proceed with the installation of required pollution control equipment. The owners intend to cease operation of the plant by January 1, 2006, pending resolution of these issues. It is the owners’ intent to preserve their ability to restart the plant at a later date should these issues be resolved, and economic analysis at that time support such a decision.

NPC’s ownership interest in Mohave comprises approximately 10% of NPC’s peak generation capacity.

Reid Gardner Station

In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, 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 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. 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. Total new pond construction and lining costs are estimated at approximately $33 million, of which, approximately $20 million has been spent through 2004. Estimated total capital expenditures planned in 2005 and 2006 are approximately $6 million and $3 million, respectively. Year to date expenditures total approximately $1 million.

In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP's inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and on December 2, 2004 issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. On July 20, 2005, NDEP issued new Notices of Alleged Violations (NOAVs). In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. NPC is continuing to provide information to NDEP as requested and is engaged in an ongoing dialogue with NDEP, including settlement discussions. Because no penalty has been specified by NDEP and discussions are continuing, management cannot reasonably estimate the amount of any potential monetary penalties that may ultimately be assessed in connection with the alleged violations. On July 26, 2005 NPC received a letter from the EPA requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC is in the process of responding to the EPA information request.

Clark Station

issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur and management is presently involved in the discovery process to support this position. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time.

NEICO

Sierra Pacific Power Company

Piñon Pine

In its 2003 General Rate Case, SPPC sought to recover all of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project from the PUCN. The coal gasifier represented an experimental technology that was being tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of a cooperative agreement with the DOE, SPPC agreed to fund 50% of the costs of constructing the Piñon Pine unit, with the DOE funding the remaining 50% of the costs of the project. SPPC’s participation in the Coal Gasification Demonstration Project was permitted and constructed with 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 was never fully operational. After numerous attempts to re-engineer various components of the coal gasifier, the technology has been determined to be unworkable. In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada in June 2004 (CV04-01434). SPPC filed its opening brief in early October 2004. Answering and Reply briefs were filed in November and December and oral argument was presented on April 29, 2005. SPPC expects the Court to rule within the third quarter of 2005, but cannot predict the outcome of the case.

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 Public Utilities Commission of Nevada to disallow a $180 million rate adjustment for NPC in its 2001 deferred energy case (as discussed in Part II of this report under Nevada Power Company 2001 Deferred Energy Case). 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. Merrill Lynch filed motions to dismiss on May 6, 2003 and June 23, 2003. The court has yet to rule on the motions to dismiss and the case is currently stayed pending resolution of NPC’s appeal of the 2001 deferred energy case currently pending before the Nevada Supreme Court.

Lawsuit Against Natural Gas Providers

On April 21, 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. On July 3, 2003, SPR and NPC filed a First Amended Complaint. Motions to dismiss were filed by all of the defendants and were heard by the court on January 27, 2004. The motions to dismiss were granted based on a filed rate defense asserted by the defendants. SPR and NPC filed a Motion to Reconsider, which was heard by the court on April 20, 2004. The court granted the Motion to Reconsider and allowed SPR and NPC to amend the complaint. A Second Amended Complaint was filed on June 4, 2004.

The Second Amended Complaint names 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 (El Paso); (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company (SoCal), and San Diego Gas and Electric (SDG&E) (collectively Sempra). New motions to dismiss were filed by all of the defendants and a hearing was held on November 29, 2004. The District Court granted the defendants’ motions to dismiss. The case has been appealed to the Ninth Circuit Court of Appeals and a briefing schedule has been set. At this time, management cannot predict the timing or outcome of a decision on this matter.

Investment Banker Complaint

On November 19, 2004, SPR and NPC filed suit in United States District Court, District of Nevada, against Citigroup, Inc., Solomon Smith Barney, Inc., J.P. Morgan Chase Bank and numerous other investment banks and financial institutions asserting claims for damages arising out of the defendants’ conduct in acting in concert with Enron to falsely portray Enron’s financial condition and induce the reliance of business counterparties, including NPC, upon the statements and representations of Enron regarding its financial health in the 1990s and early 2000 time period. The suit alleges, among other things, that the defendants aided and abetted Enron’s fraud through financial transactions with so-called Special Purpose Entities, which were designed to conceal Enron liabilities or artificially inflate revenues and reported financial condition. The complaint seeks damages in excess of $500 million.

Effective January 10, 2005, the suit was transferred to MDL-1446, In re Enron Corp. Securities, Derivative and Erisa Litigation, pending in the U.S.D.C. in Houston, Texas. At this time the Utilities are unable to predict the outcome or the timing of future proceedings related to the complaint.

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

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

The 2005 Annual Meeting of the Stockholders of Sierra Pacific Resources was held at 10:00 a.m., Pacific Daylight Time, on Monday, May 2, 2005, at Texas Station Gambling Hall & Hotel, 2101 Texas Star Lane, Las Vegas, Nevada.

Two proposals were presented for stockholder consideration: (1) election of four members of the Board of Directors to serve until the Annual Meeting in 2008, and until their successors are elected and qualified; and (2) to consider whether to adopt a shareholder proposal requesting Directors to redeem any active poison pill unless such poison pill is approved by the affirmative vote of the holders of a majority of shares present and voting as a separate ballot item, to be held as soon as may be practicable.

Four Directors, Joseph B. Anderson, Jr, Krestine M. Corbin, Philip G. Satre, and Clyde T. Turner, were elected to serve three year terms expiring at the 2008 Annual Meeting of Stockholders. The shareholder proposal was approved by the required affirmative vote of the stockholders. Directors whose term expires in 2006: Mary Lee Coleman, T.J. Day, Jerry E. Herbst. Directors whose term expires in 2007: James R. Donnelley, Walter M. Higgins, John F. O’Reilly.

The certified voting results are shown below:


Election of Directors	For		Withheld
Joseph B. Anderson, Jr.		95,271,773		6,135,259
Krestine M. Corbin		95,165,186		6,241,846
Philip G. Satre		95,230,229		6,176,803
Clyde T. Turner		88,313,941		13,093,091


PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements

Sierra Pacific Resources -
Consolidated Balance Sheets — June 30, 2005 and December 31, 2004			3

Consolidated Statements of Operations — Three Months and Six Months Ended June 30, 2005 and 2004			4

Consolidated Statements of Cash Flows — Six Months Ended June 30, 2005 and 2004			5

Nevada Power Company -
Consolidated Balance Sheets — June 30, 2005 and December 31,2004			6

Consolidated Statements of Operations — Three Months and Six Months Ended June 30, 2005 and 2004			7

Consolidated Statements of Cash Flows — Six Months Ended June 30, 2005 and 2004			8

Sierra Pacific Power Company -
Consolidated Balance Sheets — June 30, 2005 and December 31, 2004			9

Consolidated Statements of Operations — Three Months and Six Months Ended June 30, 2005 and 2004			10

Consolidated Statements of Cash Flows — Six Months Ended June 30, 2005 and 2004			11

Condensed Notes to Consolidated Financial Statements			12

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Sierra Pacific Resources			35
Nevada Power Company			39
Sierra Pacific Power Company			46

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk			57

ITEM 4. Controls and Procedures			57

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings			58

ITEM 4. Submission of Matters to a Vote of Security Holders			65

ITEM 5. Other Information			66

ITEM 6. Exhibits			66

Signature Page and Certifications			67
EX-10.1 Purchase Agreement
EX-31.1 Section 302 Certification of CEO
Ex-31.2 Section 302 Certification of CFO
EX-32.1 Section 906 Certification of CEO
EX-32.2 Section 906 Certification of CFO


							Broker
	For		Against		Abstain		Non-Votes
To consider whether to adopt a shareholder proposal requesting Directors to redeem any active poison pill unless such poison pill is approved by the affirmative vote of the holders of a majority of shares present and voting as a separate ballot item, to be held as soon as may be practicable.		52,800,821		24,709,726		1,345,506		22,550,979


	Sierra Pacific Resources
	(Registrant)

Date: August 8, 2005	By:	/s/ Michael W. Yackira

		Michael W. Yackira
		Executive Vice President
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 8, 2005	By:	/s/ John E. Brown

		John E. Brown
		Controller
		(Principal Accounting Officer)

	Nevada Power Company
	(Registrant)

Date: August 8, 2005	By:	/s/ Michael W. Yackira

		Michael W. Yackira
		Executive Vice President
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 8, 2005	By:	/s/ John E. Brown

		John E. Brown
		Controller
		(Principal Accounting Officer)

	Sierra Pacific Power Company
	(Registrant)

Date: August 8, 2005	By:	/s/ Michael W. Yackira

		Michael W. Yackira
		Executive Vice President
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 8, 2005	By:	/s/ John E. Brown

		John E. Brown
		Controller
		(Principal Accounting Officer)