SIERRA PACIFIC RESOURCES /NV/ - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 2003


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	State of	I.R.S. employer
Number	Number	Incorporation	Identification Number

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

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

0-00508	SIERRA PACIFIC POWER COMPANY	Nevada	88-0044418
	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 x No o

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

Nevada Power Company Yes o No x; Sierra Pacific Power Company Yes o No x

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


Class		Outstanding at November 10, 2003
Common Stock, $1.00 par value		117,181,075 Shares
of Sierra Pacific Resources

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.

TABLE OF CONTENTS


		SIERRA PACIFIC RESOURCES CONSOLIDATED BALANCE SHEETS
		SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF OPERATIONS
		SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CASH FLOWS
		NEVADA POWER COMPANY CONSOLIDATED BALANCE SHEETS
		NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS
		NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
		SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS
		SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS
		SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
			Sierra Pacific Resources
			Nevada Power Company
			Sierra Pacific Power Company
	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4. CONTROLS AND PROCEDURES
PART II
	ITEM 1. LEGAL PROCEEDINGS
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	ITEM 5.OTHER INFORMATION
	ITEM 6.EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURES
EX-4.1 OFFICER'S CERTIFICATE NEVADA POWER CO.
EX-4.2 9% GENERAL AND REFUNDING MORTGAGE NOTES
EX-4.3 OFFICER'S CERTIFICATE SIERRA PACIFIC POWER
EX-4.4 GENERAL AND REFUNDING MORTGAGE NOTES (D)
EX-10.1 EMPLOYMENT AGREEMENT FOR WALTER HIGGINS
EX-31.1 SECTION 302 CERTIFICATION OF THE C.E.O.
EX-31.2 SECTION 302 CERTIFICATION OF C.F.O.
EX-32.1 SECTION 906 CERTIFICATION OF CEO & CFO

SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2003

CONTENTS

PART I - FINANCIAL INFORMATION

ITEM 1.

Financial Statements

Sierra Pacific Resources -

Consolidated Balance Sheets – September 30, 2003 and December 31, 2002

Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2003 and 2002

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2003 and 2002

Nevada Power Company -

Consolidated Balance Sheets – September 30, 2003 and December 31, 2002

Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2003 and 2002

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2003 and 2002

Sierra Pacific Power Company -

Consolidated Balance Sheets – September 30, 2003 and December 31, 2002

Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2003 and 2002

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2003 and 2002

Condensed Notes to Consolidated Financial Statements

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Sierra Pacific Resources

Nevada Power Company

Sierra Pacific Power Company

ITEM 3.

Quantitative and Qualitative Disclosures about Market Risk

ITEM 4.

Controls and Procedures

PART II - OTHER INFORMATION

ITEM 1.

Legal Proceedings

ITEM 4.

Submission of Matters to a Vote of Security Holders

ITEM 5.

Other Information

ITEM 6.

Exhibits and Reports on Form 8-K

Signature Page

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


				September 30,		December 31,
				2003		2002

				(unaudited)
ASSETS
Utility Plant at Original Cost:
	Plant in service			$	6,292,119	$	5,989,701
		Less accumulated provision for depreciation			2,084,049		1,944,351

					4,208,070		4,045,350
	Construction work-in-progress				221,334		263,346

					4,429,404		4,308,696

Investments and other property, net					106,634		124,580

Current Assets:
	Cash and cash equivalents				192,372		192,064
	Restricted cash				63,412		13,705
	Accounts receivable less provision for uncollectible accounts:
			2003-$39,394 ; 2002-$42,001		395,578		358,972
	Deferred energy costs - electric				294,057		268,979
	Deferred energy costs - gas				3,446		17,045
	Materials, supplies and fuel, at average cost				78,972		87,348
	Risk management assets (Note 10)				37,231		29,570
	Other				65,531		48,898

					1,130,599		1,016,581

Deferred Charges and Other Assets:
	Goodwill				309,971		309,971
	Deferred energy costs - electric				545,823		685,875
	Regulatory tax asset				159,501		163,889
	Other regulatory assets				142,289		136,933
	Risk management assets (Note 10)				137		368
	Risk management regulatory assets - net (Note 10)				31,693		44,970
	Other				96,640		92,250

					1,286,054		1,434,256

Assets of Business Sold (Note 8)					—		12,862

				$	6,952,691	$	6,896,975

CAPITALIZATION AND LIABILITIES
Capitalization:
	Common shareholders’ equity			$	1,457,272	$	1,327,166
	Preferred stock				50,000		50,000
	NPC obligated mandatorily redeemable preferred trust securities (Note 4)				—		188,872
	Long-term debt				3,572,344		3,062,815

					5,079,616		4,628,853

Current Liabilities:
	Current maturities of long-term debt				256,838		672,963
	Accounts payable				189,057		232,424
	Accrued interest				99,099		50,308
	Dividends declared				1,046		1,045
	Accrued salaries and benefits				28,556		20,798
	Deferred taxes				154,622		123,507
	Risk management liabilities (Note 10)				40,461		69,953
	Contract termination reserves (Note 11)				35,280		—
	Other current liabilities				33,246		46,719

					838,205		1,217,717

Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
	Deferred federal income taxes				250,917		336,875
	Deferred investment tax credit				45,903		48,492
	Regulatory tax liability				39,730		42,718
	Customer advances for construction				126,790		116,032
	Accrued retirement benefits				107,417		107,580
	Risk management liabilities (Note 10)				717		3,917
	Contract termination reserves (Note 11)				348,179		312,594
	Other				115,217		81,410

					1,034,870		1,049,618

Liabilities of Business Sold (Note 8)					—		787

				$	6,952,691	$	6,896,975

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Share and Per Share Amounts) (Unaudited)


				Three Months Ended						Nine Months Ended
				September 30,						September 30,

				2003			2002			2003			2002

OPERATING REVENUES:
	Electric			$	890,138		$	998,256		$	2,057,781		$	2,253,425
	Gas				13,930			18,473			114,421			99,139
	Other				809			642			2,111			2,264

					904,877			1,017,371			2,174,313			2,354,828

OPERATING EXPENSES:
	Operation:
		Purchased power			423,446			604,683			905,327			1,546,394
		Fuel for power generation			192,825			120,668			393,864			356,084
		Gas purchased for resale			7,133			9,884			77,332			61,585
		Deferred energy costs disallowed			—			—			90,964			487,224
		Deferral of energy costs - electric - net			(58,141	)		(41,425	)		44,729			(309,203	)
		Deferral of energy costs - gas - net			2,200			4,281			14,023			14,649
		Impairment of subsidiary assets (Note 8)			—			—			32,911			—
		Other			74,065			68,142			233,673			200,265
	Maintenance				13,972			12,904			54,799			46,826
	Depreciation and amortization				49,552			43,661			142,236			130,012
	Taxes:
		Income taxes			23,288			41,044			(46,602	)		(145,565	)
		Other than income			11,093			10,257			33,715			33,508

					739,433			874,099			1,976,971			2,421,779

OPERATING INCOME (LOSS)					165,444			143,272			197,342			(66,951	)

OTHER INCOME (EXPENSE):
	Allowance for other funds used during construction				1,039			(272	)		3,883			382
	Interest accrued on deferred energy				6,684			10,712			21,142			11,644
	Other income				7,151			4,882			20,127			12,774
	Other expense				(3,751	)		(4,031	)		(10,750	)		(15,825	)
	Income taxes				(24,619	)		(3,553	)		6,956			(2,121	)
	Unrealized gain (loss) on derivative instrument ( Note 10)				61,513			—			(46,065	)		—

					48,017			7,738			(4,707	)		6,854

			Total Income (Loss) Before Interest Charges		213,461			151,010			192,635			(60,097	)

INTEREST CHARGES:
	Long-term debt				75,818			56,696			219,344			170,935
	Other				50,823			11,060			70,531			23,827
	Allowance for borrowed funds used during construction				(1,481	)		(902	)		(4,368	)		(3,483	)

					125,160			66,854			285,507			191,279

	Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities (Note 4)				—			3,793			—			11,379

INCOME (LOSS) FROM CONTINUING OPERATIONS					88,301			80,363			(92,872	)		(262,755	)

DISCONTINUED OPERATIONS (Note 8)
	Loss from operations (including loss on disposal of $9,555 in 2003)				(707	)		(56	)		(11,160	)		(1,162	)
	Income tax benefit				248			42			3,906			384

	Loss from discontinued operations				(459	)		(14	)		(7,254	)		(778	)

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, net of tax					—			—			—			(1,566	)

NET INCOME (LOSS)					87,842			80,349			(100,126	)		(265,099	)

Preferred stock dividend requirements of SPPC					975			975			2,925			2,925

INCOME (LOSS) APPLICABLE TO COMMON STOCK				$	86,867		$	79,374		$	(103,051	)	$	(268,024	)

Amount per share - basic and diluted
		Income/(Loss) from continuing operations (Note 6)		$	0.29		$	0.78		$	(0.81	)	$	(2.61	)
		Income/(Loss) per share applicable to common stock (Note 6)		$	0.28		$	0.78		$	(0.89	)	$	(2.62	)
Weighted Average Shares of Common Stock Outstanding					117,177,323			102,132,465			115,294,693			102,117,926

Dividends Paid Per Share of Common Stock				$	—		$	—		$	—		$	0.20

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)


					Nine Months Ended
					September 30,

					2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net Loss				$	(100,126	)	$	(265,099	)
	Non-cash items included in income:
		Depreciation and amortization				142,236			131,422
		Deferred taxes and deferred investment tax credit				(8,575	)		79,410
		AFUDC and capitalized interest				(8,251	)		(3,865	)
		Amortization of deferred energy costs - electric				191,196			130,667
		Amortization of deferred energy costs - gas				10,784			8,950
		Deferred energy costs disallowed, net of taxes				59,127			317,977
		Unrealized loss on derivative instrument, net of taxes				29,942			—
		Impairment of assets of subsidiary, net of taxes				21,392			—
		Loss on disposal of subsidiary, net of taxes				6,211			—
		Other non-cash				(19,083	)		(8,387	)
	Changes in certain assets and liabilities:
		Accounts receivable				(36,606	)		(115,247	)
		Deferral of energy costs - electric				(151,435	)		(123,308	)
		Deferral of energy costs - gas				2,815			3,408
		Materials, supplies and fuel				8,376			(1,506	)
		Prepaid interest for convertible debt				(53,408	)		—
		Other current assets				(12,932	)		(32,658	)
		Accounts payable				(43,367	)		166,144
		Income tax receivable				—			108,992
		Other current liabilities				43,076			35,293
		Other assets				11,491			—
		Other liabilities				72,007			32,396

Net Cash from Operating Activities						164,870			464,589

CASH FLOWS FROM INVESTING ACTIVITIES:
			Additions to utility plant			(271,155	)		(259,923	)
			AFUDC and other charges to utility plant			8,251			3,865
			Customer advances for construction			10,758			6,268
			Contributions in aid of construction			9,656			32,381

			Net cash used for utility plant			(242,490	)		(217,409	)
			Investments and other property - net			(9,026	)		(55,349	)

Net Cash from Investing Activities						(251,516	)		(272,758	)

CASH FLOWS FROM FINANCING ACTIVITIES:
			Increase in short-term borrowings			—			173,000
			Proceeds from issuance of long-term debt			650,842			—
			Retirement of long-term debt			(560,358	)		(80,272	)
			Sale of Common Stock			(981	)		187
			Dividends paid			(2,549	)		(23,510	)

Net Cash from Financing Activities						86,954			69,405

Net Increase in Cash and Cash Equivalents						308			261,236
Beginning Balance in Cash and Cash Equivalents						192,064			99,109

Ending Balance in Cash and Cash Equivalents					$	192,372		$	360,345

Supplemental Disclosures of Cash Flow Information:
			Cash paid (received) during period for:
				Interest	$	188,482		$	154,754
				Income taxes	$	(1,521	)	$	(185,011	)
Noncash financing activities (Note 4):
				Exchanged Floating Rate Notes for SPR common stock	$	8,750
				Exchanged Premium Income Equity Securities for SPR common stock	$	104,782

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


				September 30,		December 31,
				2003		2002

				(Unaudited)
ASSETS
Utility Plant at Original Cost:
	Plant in service			$	3,783,204	$	3,542,300
		Less accumulated provision for depreciation			1,098,987		1,017,494

					2,684,217		2,524,806
	Construction work-in-progress				97,516		173,189

					2,781,733		2,697,995

Investments and other property, net					33,275		20,295

Current Assets:
	Cash and cash equivalents				97,249		95,009
	Restricted cash				—		3,850
	Accounts receivable less provision for uncollectible accounts:
			2003-$33,782; 2002-$33,841		276,449		202,590
	Deferred energy costs - electric				240,909		213,193
	Materials, supplies and fuel, at average cost				41,886		44,074
	Risk management assets (Note 10)				20,795		28,173
	Other				45,700		31,602

					722,988		618,491

Deferred Charges and Other Assets:
	Deferred energy costs - electric				419,302		524,345
	Regulatory tax asset				103,229		106,071
	Other regulatory assets				59,106		53,109
	Risk management assets (Note 10)				137		368
	Risk management regulatory assets - net (Note 10)				5,257		1,491
	Other				51,901		46,357

					638,932		731,741

				$	4,176,928	$	4,068,522

CAPITALIZATION AND LIABILITIES
Capitalization:
	Common shareholder’s equity				1,174,347	$	1,149,131
	NPC obligated mandatorily redeemable preferred trust securities (Note 4)				—		188,872
	Long-term debt				1,893,451		1,488,597

					3,067,798		2,826,600

Current Liabilities:
	Current maturities of long-term debt				135,123		354,677
	Accounts payable				120,042		143,002
	Accounts payable, affiliated companies				2,893		4,287
	Accrued interest				46,360		29,892
	Dividends declared				78		78
	Accrued salaries and benefits				12,198		7,781
	Deferred taxes				124,376		90,616
	Risk management liabilities (Note 10)				13,861		29,908
	Contract termination reserves (Note 11)				24,192		—
	Other current liabilities				25,240		22,115

					504,363		682,356

Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
	Deferred federal income taxes				107,294		129,687
	Deferred investment tax credit				20,680		21,902
	Regulatory tax liability				16,322		17,300
	Customer advances for construction				74,066		66,434
	Accrued retirement benefits				49,409		54,216
	Contract termination reserves (Note 11)				254,765		225,816
	Other				82,231		44,211

					604,767		559,566

				$	4,176,928	$	4,068,522

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

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands) (Unaudited)


				Three Months Ended						Nine Months Ended
				September 30,						September 30,

				2003			2002			2003			2002

OPERATING REVENUES:
	Electric			$	639,661		$	712,536		$	1,396,825		$	1,545,867

OPERATING EXPENSES:
	Operation:
		Purchased power			301,683			440,559			620,712			1,102,551
		Fuel for power generation			126,839			87,864			246,643			245,060
		Deferred energy costs disallowed			—			—			45,964			434,123
		Deferral of energy costs-net			(35,967	)		(43,224	)		48,260			(238,059	)
		Other			44,749			39,250			136,964			116,520
	Maintenance				9,203			8,050			38,390			31,576
	Depreciation and amortization				28,474			24,975			81,095			72,924
	Taxes:
		Income taxes			30,556			39,944			3,734			(116,536	)
		Other than income			6,387			5,935			19,429			19,122

					511,924			603,353			1,241,191			1,667,281

OPERATING INCOME (LOSS)					127,737			109,183			155,634			(121,414	)

OTHER INCOME (EXPENSE):
	Allowance for other funds used during construction				281			(262	)		1,922			239
	Interest accrued on deferred energy				5,952			8,506			16,896			5,411
	Other income				4,277			2,451			11,633			3,792
	Other expense				(1,441	)		(3,184	)		(4,491	)		(9,745	)
	Income taxes				(3,084	)		(2,840	)		(8,277	)		(297	)

					5,985			4,671			17,683			(600	)

			Total Income (Loss) Before Interest Charges		133,722			113,854			173,317			(122,014	)

INTEREST CHARGES:
	Long-term debt				37,600			23,714			104,215			70,668
	Other				34,171			7,251			46,165			14,133
	Allowance for borrowed funds used during construction				(573	)		(208	)		(2,149	)		(2,169	)

					71,198			30,757			148,231			82,632

	Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities (Note 4)				—			3,793			—			11,379

NET INCOME (LOSS)				$	62,524		$	79,304		$	25,086		$	(216,025	)

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

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands) (Unaudited)


				Nine Months Ended
				September, 2003

				2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net Income / (Loss)			$	25,086		$	(216,025	)
	Non-cash items included in income:
		Depreciation and amortization			81,095			72,924
		Deferred taxes and deferred investment tax credit			28,097			68,430
		AFUDC and capitalized interest			(4,071	)		(2,408	)
		Amortization of deferred energy costs			156,065			112,959
		Deferred energy costs disallowed (net of taxes)			29,876			282,181
		Other non-cash			(16,908	)		(14,184	)
	Changes in certain assets and liabilities:
		Accounts receivable			(73,859	)		(95,791	)
		Deferral of energy costs			(124,701	)		(127,429	)
		Materials, supplies and fuel			2,188			3,077
		Other current assets			(10,248	)		(14,843	)
		Accounts payable			(24,354	)		129,728
		Income tax receivable			—			70,807
		Other current liabilities			24,010			11,961
		Other assets			8,208			—
		Other liabilities			70,436			18,832

Net Cash from Operating Activities					170,920			300,219

CASH FLOWS FROM INVESTING ACTIVITIES:
		Additions to utility plant			(166,993	)		(196,006	)
		AFUDC and other charges to utility plant			4,071			2,408
		Customer advances (refunds) for construction			7,632			3,072
		Contributions in aid of construction			2,941			27,635

		Net cash used for utility plant			(152,349	)		(162,891	)
		Investments and other property - net			(12,758	)		(2,200	)

Net Cash from Investing Activities					(165,107	)		(165,091	)

CASH FLOWS FROM FINANCING ACTIVITIES:
		Increase in short-term borrowings			—			69,500
		Proceeds form the issuance of long-term debt			350,000			—
		Retirement of long-term debt			(353,573	)		(5,387	)
		Investment by parent company			—			10,000
		Dividends paid			—			(10,000	)

Net Cash from Financing Activities					(3,573	)		64,113

Net Increase in Cash and Cash Equivalents					2,240			199,241
Beginning Balance in Cash and Cash Equivalents					95,009			8,508

Ending Balance in Cash and Cash Equivalents				$	97,249		$	207,749

Supplemental Disclosures of Cash Flow Information:
		Cash paid (received) during period for:
			Interest		96,903		$	66,400
			Income taxes		—		$	(102,904	)

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


			September 30,		December 31,
			2003		2002

			(Unaudited)
ASSETS
Utility Plant at Original Cost:
	Plant in service		$	2,508,915	$	2,447,401
		Less accumulated provision for depreciation		985,062		926,857

				1,523,853		1,520,544
	Construction work-in-progress			123,818		90,157

				1,647,671		1,610,701

Investments and other property, net				929		874

Current Assets:
	Cash and cash equivalents			83,503		88,910
	Restricted cash			6,626		9,605
	Accounts receivable less provision for uncollectible accounts:
		2003 - $5,612 2002 - $10,343		118,383		154,821
	Accounts receivable, affiliated companies			57,913		58,680
	Deferred energy costs - electric			53,148		55,786
	Deferred energy costs - gas			3,446		17,045
	Materials, supplies and fuel, at average cost			35,603		41,727
	Risk management assets (Note 10)			16,436		1,397
	Other			16,529		12,955

				391,587		440,926

Deferred Charges and Other Assets:
	Deferred energy costs - electric			126,521		161,530
	Regulatory tax asset			56,272		57,818
	Other regulatory assets			63,028		64,149
	Risk management regulatory assets - net (Note 10)			26,436		43,479
	Other			21,229		19,013

				293,486		345,989

			$	2,333,673	$	2,398,490

CAPITALIZATION AND LIABILITIES
Capitalization:
	Common shareholder’s equity		$	612,156	$	639,295
	Preferred stock			50,000		50,000
	Long-term debt			913,297		914,788

				1,575,453		1,604,083

Current Liabilities:
	Current maturities of long-term debt			101,400		101,400
	Accounts payable			43,758		71,247
	Accrued interest			24,761		12,136
	Dividends declared			968		968
	Accrued salaries and benefits			13,245		10,812
	Deferred taxes			30,245		32,891
	Risk management liabilities (Note 10)			26,600		40,045
	Contract termination reserves (Note 11)			11,088		—
	Other current liabilities			7,106		10,864

				259,171		280,363

Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
	Deferred federal income taxes			229,448		251,487
	Deferred investment tax credit			25,223		26,590
	Regulatory tax liability			23,408		25,418
	Customer advances for construction			52,724		49,598
	Accrued retirement benefits			49,253		44,856
	Risk management liabilities (Note 10)			717		3,917
	Contract termination reserves (Note 11)			93,414		86,778
	Other			24,862		25,400

				499,049		514,044

			$	2,333,673	$	2,398,490

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands) (Unaudited)


				Three Months Ended						Nine Months Ended
				September 30,						September 30,

				2003			2002			2003			2002

OPERATING REVENUES:
	Electric			$	250,476		$	285,720		$	660,956		$	707,558
	Gas				13,931			18,473			114,421			99,139

					264,407			304,193			775,377			806,697

OPERATING EXPENSES:
	Operation:
		Purchased power			121,763			164,124			284,615			443,843
		Fuel for power generation			65,986			32,804			147,221			111,024
		Gas purchased for resale			7,133			9,884			77,332			61,585
		Deferred energy costs disallowed			—			—			45,000			53,101
		Deferral of energy costs - electric - net			(22,174	)		1,799			(3,531	)		(71,144	)
		Deferral of energy costs - gas - net			2,200			4,281			14,023			14,649
		Other			26,684			25,319			87,522			75,974
	Maintenance				4,769			4,854			16,409			15,250
	Depreciation and amortization				20,811			19,034			60,478			57,186
	Taxes:
		Income taxes			(21	)		7,601			(16,229	)		(9,037	)
		Other than income			4,668			4,472			14,179			14,129

					231,819			274,172			727,019			766,560

OPERATING INCOME					32,588			30,021			48,358			40,137

OTHER INCOME (EXPENSE):
	Allowance for other funds used during construction				758			(10	)		1,961			143
	Interest accrued on deferred energy				732			2,207			4,246			6,233
	Other income				1,450			1,880			3,550			5,450
	Other expense				(1,450	)		(1,337	)		(5,057	)		(5,146	)
	Income taxes				(454	)		(796	)		(1,233	)		(1,906	)

					1,036			1,944			3,467			4,774

			Total Income Before Interest Charges		33,624			31,965			51,825			44,911

INTEREST CHARGES:
		Long-term debt			19,174			16,173			56,914			48,638
		Other			15,675			2,943			21,404			7,051
		Allowance for borrowed funds used during construction			(908	)		(694	)		(2,219	)		(1,314	)

					33,941			18,422			76,099			54,375

NET INCOME (LOSS)					(317	)		13,543			(24,274	)		(9,464	)

Preferred Dividend Requirements					975			975			2,925			2,925

Income (Loss) applicable to common stock				$	(1,292	)	$	12,568		$	(27,199	)	$	(12,389	)

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands) (Unaudited)


				Nine Months Ended
				September, 2003

				2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss				$	(24,274	)	$	(9,464	)
	Non-cash items included in income:
		Depreciation and amortization			60,478			57,186
		Deferred taxes and deferred investment tax credit			(26,518	)		10,979
		AFUDC and capitalized interest			(4,180	)		(1,457	)
		Amortization of deferred energy costs - electric			35,131			17,708
		Amortization of deferred energy costs - gas			10,784			8,950
		Deferred energy costs disallowed (net of taxes)			29,250			35,796
		Early retirement and severance amortization			1,873			2,082
		Other non-cash			(4,247	)		(10,548	)
	Changes in certain assets and liabilities:
		Accounts receivable			37,205			(54,994	)
		Deferral of energy costs - electric			(26,734	)		4,121
		Deferral of energy costs - gas			2,815			3,408
		Materials, supplies and fuel			6,124			(4,126	)
		Other current assets			(595	)		(14,165	)
		Accounts payable			(27,489	)		(13,285	)
		Income tax receivable			—			43,385
		Other current liabilities			11,300			13,738
		Other assets			3,284			—
		Other liabilities			4,999			12,096

Net Cash from Operating Activities					89,206			101,410

CASH FLOWS FROM INVESTING ACTIVITIES:
		Additions to utility plant			(104,162	)		(63,917	)
		AFUDC and other charges to utility plant			4,180			1,457
		Customer advances for construction			3,126			3,196
		Contributions in aid of construction			6,714			4,746

		Net cash used for utility plant			(90,142	)		(54,518	)
		Disposal of investments and other property - net			(55	)		734

Net Cash from Investing Activities					(90,197	)		(53,784	)

CASH FLOWS FROM FINANCING ACTIVITIES:
		Increase in short-term borrowings			—			103,500
		Retirement of long-term debt			(1,491	)		(6,200	)
		Investment by parent company			—			10,000
		Dividends paid			(2,925	)		(22,830	)

Net Cash from Financing Activities					(4,416	)		84,470

Net Increase (Decrease) in Cash and Cash Equivalents					(5,407	)		132,096
Beginning Balance in Cash and Cash Equivalents					88,910			11,772

Ending Balance in Cash and Cash Equivalents				$	83,503		$	143,868

Supplemental Disclosures of Cash Flow Information:
		Cash (received) paid during period for:
			Interest	$	50,100		$	38,294
			Income taxes	$	(1,521	)	$	(62,109	)

The accompanying notes are an integral part of the financial statements

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Management’s Statement (SPR, NPC, SPPC)

In the opinion of the management of Sierra Pacific Resources (SPR), Nevada Power Company (NPC), and Sierra Pacific Power Company (SPPC), the accompanying unaudited interim consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail 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, 2002.

The results of operations and cash flows of SPR, NPC and SPPC for the three month and nine month periods ended September 30, 2003, are not necessarily indicative of the results to be expected for the full year. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed below.

Enron Litigation

In 2001, Enron Power Marketing, Inc. (Enron) filed a complaint with the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court) against NPC and SPPC (the Utilities) seeking to recover liquidated damages for power supply contracts terminated by Enron in May 2002 and for unpaid power previously delivered to the Utilities (as defined below). The Utilities denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron’s ability to perform) and fraud, unfair trade practices and market manipulation. The Utilities also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for other unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets, wrongful termination of its transactions with the Utilities, and fraudulent inducement to enter into transactions with Enron, among other issues. See SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002 for additional information regarding the Enron litigation.

On September 26, 2003, the Bankruptcy Court entered a judgment (the Judgment) in favor of Enron for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment requires 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. The Bankruptcy Court also dismissed the Utilities’ counter-claims against Enron, dismissed the Utilities’ counter-claims against Enron Corp., the parent of Enron, and denied the Utilities’ motion to dismiss or stay the proceedings pending the final outcome of their Federal Energy Regulatory Commission proceedings against Enron. Based on the prejudgment rate of 12%, NPC and SPPC recognized additional interest expense of $27.8 million and $12.4 million, respectively, in contract termination reserves in the third quarter of 2003. Also, NPC and SPPC recorded additional contract termination reserves for liquidated damages of $6.6 million and $2.1 million, respectively, in the third quarter of 2003. The Bankruptcy Court’s order provides that until paid, the amounts owed by the Utilities will accrue interest post-Judgment at a rate of 1.21% per annum.

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 $281,695 in cash by NPC for prejudgment interest. NPC and SPPC have sufficient regulatory authority from the Public Utilities Commission of Nevada (PUCN) to comply with the Bankruptcy Court’s ruling. Additionally, the Utilities have been 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 will lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. 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 their deferred energy rate cases. Furthermore, the Bankruptcy Court will review the Utilities’ abilities to provide additional cash collateral within two weeks after the $35 million is posted by NPC and SPPC.

NPC and SPPC have established reserves, included in their Consolidated Balance Sheets as “Contract termination reserves,” of $235 million and $103 million, respectively, for power supply contracts terminated by Enron and associated interest. Correspondingly, pursuant to the deferred energy accounting provisions of AB 369, included in NPC and SPPC deferred energy balances as of September 30, 2003, is approximately $200 million and $87 million, (which excludes interest costs discussed below) respectively, for recovery in rates in future periods associated with the power supply contracts terminated by Enron. If NPC and SPPC are required to pay part or all of the amounts reserved, the Utilities will pursue recovery of the amounts 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 adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC. The Utilities intend to appeal the Judgment of the Bankruptcy Court to the U.S. District Court of New York.

Through September 30, 2003, interest costs related to the Judgment of $36 million and $16 million for NPC and SPPC, respectively, were charged as interest expense and were not included in their deferred energy balances. If the Utilities are successful in their appeal, amounts previously charged to interest expense would be reversed and recognized in income in the respective period. Similarly amounts for power supply contracts terminated by Enron included in the deferred energy balances would be reversed. If the Utilities are unsuccessful in their appeal, they have not determined whether to seek recovery of the interest costs. The Utilities are unable to predict the outcome of their appeal of the Judgment of the Bankruptcy Court.

Any requirement to pay the Judgment or to provide cash collateral, in excess of the $35 million the Utilities are required to deposit into escrow, described above, for Enron’s claims for termination payments could adversely affect SPR’s, NPC’s and SPPC’s cash flow, financial condition and liquidity, and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Sierra Pacific Resources

SPR, on a stand-alone basis, had cash and cash equivalents of approximately $11.1 million at September 30, 2003. During the fourth quarter of 2003, SPR has approximately $18.6 million of interest due on its existing debt securities. Currently, SPR expects to meet its interest obligations for the fourth quarter of 2003 through the payment of a dividend by SPPC to SPR.

SPR’s future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC’s ability to continue to pay dividends to SPR, on NPC’s financial stability and the restoration of its ability to pay dividends to SPR, and on SPR’s ability to access the capital markets or otherwise refinance maturing and/or convertible debt. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs (including terminated power supply contracts) in future rate cases, a requirement to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron or provide cash collateral, in excess of the $35 million the Utilities are required to deposit into escrow within 90 days from the order date, for Enron’s claims for termination payments under the judgment, could adversely affect SPR’s, NPC’s and SPPC’s cash flow, financial condition and liquidity and could make it difficult for SPR, NPC and SPPC to operate outside of bankruptcy.

The provisions that currently restrict dividend payments by NPC or SPPC have adversely affected SPR’s liquidity and will continue to negatively impact SPR’s liquidity until those provisions are no longer in effect. Management is currently in the process of seeking consent for a modification of the financial covenant contained in NPC’s first mortgage indenture. There can be no assurance that any such consent can be obtained or that any non-consenting first mortgage bonds could be redeemed or defeased prior to their stated maturity. The regulatory limitation contained in the PUCN’s Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003.

Nevada Power Company

NPC had cash and cash equivalents of approximately $97.2 million at September 30, 2003.

NPC’s liquidity would be significantly affected by a requirement to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron, a requirement to provide cash collateral in excess of the $24 million NPC is required to deposit into escrow within 90 days from the order date, for Enron’s claims for termination payments under the judgment, or unfavorable rulings by the PUCN in future NPC deferred energy rate cases (including terminated power supply contracts). In response to the announcement of the decision of the Bankruptcy Court on August 28, 2003, in favor of Enron, S&P and Moody’s placed NPC on “credit watch with negative implications” and “negative rating outlook,” respectively. Future downgrades by either S&P or Moody’s could preclude or reduce NPC’s access to the capital markets, and could adversely affect NPC’s ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing and regulatory contingencies, as discussed in Note 11, Commitments and Contingencies, could have a material adverse effect on NPC’s financial condition and liquidity, and could make it difficult for NPC to continue to operate outside of bankruptcy.

Sierra Pacific Power Company

SPPC had cash and cash equivalents of approximately $83.5 million at September 30, 2003.

SPPC’s liquidity would be significantly affected by a requirement to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron, a requirement to provide cash collateral in excess of the $11 million SPPC is required to deposit into escrow within 90 days from the order date, for Enron’s claims for termination payments under the judgment, or unfavorable rulings by the PUCN in future SPPC deferred energy rate cases (including terminated power supply contracts). In response to the announcement of the decision of the Bankruptcy Court on August 28, 2003, in favor of Enron, S&P and Moody’s placed SPPC on “credit watch with negative implications” and “negative rating outlook,” respectively. Future downgrades by either S&P or Moody’s could preclude or reduce SPPC’s access to the capital markets and could adversely affect SPPC’s ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing and regulatory contingencies, as discussed in Note 11, Commitments and Contingencies, could have a material adverse effect on SPPC’s financial condition and liquidity, and could make it difficult for SPPC to continue to operate outside of bankruptcy.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Principles of Consolidation

The consolidated financial statements of SPR include the accounts of SPR and its wholly-owned subsidiaries, NPC and SPPC, 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). Sierra Energy Company dba e·three (e·three) is a discontinued operation and as such is reported separately on the financial statements of SPR. The consolidated financial statements of NPC include the accounts of NPC and its wholly-owned subsidiaries, NEICO, NVP Capital I (Trust) and NVP Capital III (Trust). The consolidated financial statements of SPPC include the accounts of SPPC and its wholly- owned subsidiaries, GPSF-B, Piñon Pine Corp. (PPC), Piñon Pine Investment Co., Piñon Pine Company, L.L.C. and Sierra Pacific Funding L.L.C. All significant intercompany transactions and balances have been eliminated in consolidation.

Reclassifications

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

Nevada Power Company Financial Statements

The presentation of NPC’s consolidated statement of operations for the three months and nine months ended September 30, 2002, and NPC’s consolidated statement of cash flows for the nine months ended September 30, 2002, have been revised. Specifically, the effects of the revisions were to eliminate the line item “Equity in earnings (losses) of Sierra Pacific Resources” of, (the following dollars are in thousands), $70 and $(51,999) on NPC’s Consolidated Statement of Operations for the three and nine months ended September 30, 2002, respectively, and to eliminate the line item “Equity in losses of SPR” of $51,999, on NPC’s Consolidated Statement of Cash Flows for the nine months ended September 30, 2002. For additional information regarding this change in presentation, see Note 1, Summary of Significant Accounting Policies of Notes to Financial Statements in SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

Recent Pronouncements

In November 2002, the Financial Accounting Standards Board (FASB) issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees” (FIN 45), which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements were effective for financial statements of interim or annual periods beginning January 1, 2003. As of September 30, 2003, all guarantees of SPR and its subsidiaries were intercompany, whereby the parent issued the guarantees on behalf of its consolidated subsidiaries to a third party. Therefore, there was no impact on the financial position, results of operation or cash flows of SPR, NPC or SPPC as a result of the adoption.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which elaborates on Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” Among other requirements, FIN 46 provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. Management believes under the current provisions of FIN 46, we would be required to deconsolidate NPC’s Trust I and Trust II subsidiaries. However, in October, 2003, the FASB issued FASB Staff Position (FSP) “46-6 Effective Date of FIN 46,” delaying the implementation of FIN 46 to modify certain provisions for all public entities until the first interim or annual period ending after December 15, 2003. We are unable to determine the ultimate outcome of FASB’s modification as such, we have elected to delay adoption of FIN 46 as permitted and continue to monitor and evaluate further developments. Furthermore, management believes the effect of adopting FIN 46 will not have a material impact on the financial position, results of operations or cash flows of SPR, NPC or SPPC.

On April 30, 2003, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 149, which amends accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The Statement clarifies the circumstances under which a contract with an initial net investment meets the characteristics of a derivative as discussed in SFAS 133. In addition, SFAS 149 clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 has had no effect on the financial position, results of operation or cash flows of SPR, NPC or SPPC.

On May 15, 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” which requires that certain financial instruments with characteristics of both liabilities and equities be

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

classified as liabilities by their issuers. The provisions of SFAS No. 150, which also include a number of new disclosure requirements, are effective for (1) instruments entered into or modified after May 31, 2003 and (2) pre-existing instruments as of the beginning of the first interim period that commences after June 15, 2003. NPC’s obligated mandatorily redeemable preferred trust securities are subject to the provisions of SFAS No. 150.

The application of SFAS No. 150 to SPR’s and NPC’s balance sheet resulted in the presentation of NPC’s trust preferred securities, previously reported as NPC obligated mandatorily redeemable preferred trust securities, as Long-Term Debt. NPC’s payments on the obligations, previously classified on the income statement as, Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities are reported as interest charges on Long-Term Debt for the periods ending September 30, 2003, prior year amounts have not been restated. See Note 4, Long-Term Debt for further information.

Deferral of Energy Costs

NPC and SPPC implemented deferred energy accounting on March 1, 2001. See Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, 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 September 30, 2003 (dollars in thousands):


		September 30, 2003

		NPC		SPPC		SPPC			SPR
Description		Electric		Electric		Gas			Total

Unamortized balances approved for collection in current rates		$	322,710	$	55,432	$	16,938		$	395,080
Balances accumulated since end of periods submitted for PUCN approval (1)			92,911		40,205		(13,492	)		119,624
Terminated suppliers (2)			244,590		84,032		—			328,622

	Total	$	660,211	$	179,669	$	3,446		$	843,326

(1) Credits represent over-collections, that is, the extent to which gas or fuel and purchased power costs recovered through rates exceed actual gas or fuel and purchased power costs.

(2) Amounts related to terminated suppliers are discussed in Note 11, Commitments & Contingencies and Note 17, Commitments and Contingencies, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

Stock Compensation Plans

In December 2002, the FASB released SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure,” as an amendment to SFAS No. 123, “Accounting for Stock-Based Compensation.” SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002, has adopted the updated disclosure requirements set forth in SFAS No. 148. At September 30, 2003, SPR had several stock-based compensation plans which are described more fully in Note 15, Stock Compensation Plans, in the Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Combined Annual Report on Form 10-K for the year ended December 31, 2002. SPR applies Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” in accounting for its stock option plans. 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 provisions of SFAS No. 123, SPR’s income (loss) applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except per share):

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


			Three Months Ended					Nine Months Ended
			September 30,					September 30,
			2003		2002			2003			2002

Stock Compensation Cost included in Net Income (Loss) as Reported, net of related tax effects		As Reported	$	66	$	(127	)	$	90		$	(897	)

Earnings (Loss) applicable to Common Stock (1)		As Reported	$	51,578	$	79,374		$	(103,051	)	$	(268,024	)
	Less: Stock Compensation Cost, net of related tax effects	Pro Forma		17		512			1,234			1,535

Earnings (Loss) applicable to Common Stock		Pro Forma	$	51,561	$	78,862		$	(104,285	)	$	(269,559	)

Basic Earnings (Loss) Per Share		As Reported	$	0.28	$	0.78		$	(0.89	)	$	(2.62	)
		Pro Forma	$	0.28	$	0.77		$	(0.90	)	$	(2.64	)
Diluted Earnings (Loss) Per Share		As Reported	$	0.28	$	0.78		$	(0.89	)	$	(2.62	)
		Pro Forma	$	0.28	$	0.77		$	(0.90	)	$	(2.64	)

(1) Earnings for the quarter have been adjusted in accordance with EITF D-95. See Note 6, Earnings Per Share for discussion

Note 2. Asset Retirement Obligations (AROs)

Effective January 1, 2003, the Utilities adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires NPC to recognize an estimated liability for the retirement of generation plant assets specified in land leases for NPC’s jointly-owned Navajo generating station because, at the expiration of the leases, the leases require the lessees to remove the facilities upon request of the Navajo Nation. However, the retirement obligation and corresponding charges recognized were immaterial to the financial statements of NPC. NPC also redesignated amounts from Accumulated Depreciation to a regulatory liability in order to reflect the estimated costs of removal collected through rates. NPC amortizes the amount added to Electric Plant In Service and recognizes accretion expense in connection with the discounted liability over the estimated remaining life of the Navajo generating station assets. SPPC has no significant asset retirement obligations.

NPC and SPPC also collect removal costs in regulated rates for certain assets that do not have associated legal asset retirement obligations. As of September 30, 2003, NPC and SPPC estimate that they had approximately $136 million and $154 million related to such removal costs recorded in Accumulated Depreciation, respectively.

Note 3. Short-Term Borrowings

Nevada Power Company

On June 30, 2003, NPC entered into a Credit Agreement, which provided for a $60 million revolving credit facility to provide additional liquidity to NPC for its summer 2003 power purchases. This facility was paid off in full on August 11, 2003, and was terminated on August 18, 2003.

On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million. The accounts receivable purchase facility was renewed on October 28, 2003, and will expire on October 26, 2004. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purchase subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

receivables. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with NPC’s receivables facility, SPR has agreed to guaranty NPC’s performance of certain obligations as a seller and servicer under the facility.

NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of NPC’s obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond.

NPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. As of October 31, 2003, this facility had not been activated.

Sierra Pacific Power Company

On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million. The accounts receivable purchase facility was renewed on October 28, 2003, and will expire on October 26, 2004. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and gas to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased receivables. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with SPPC’s receivables facility, SPR has agreed to guaranty SPPC’s performance of certain obligations as a seller and servicer under the facility.

SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of SPPC’s obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond.

SPPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. As of October 31, 2003, this facility had not been activated.

Note 4. Long-Term Debt

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

As of September 30, 2003, 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 2003, each of the next four years and thereafter is shown below (in thousands of dollars):

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


							SPR Holding Co.			SPR
	NPC *			SPPC			and Other Subs. **			Consolidated

2003	$	980		$	19,103		$	20,315		$	40,398
2004		135,570			83,400			—			218,970
2005		6,091			100,400			300,000			406,491
2006		6,509			52,400			—			58,909
2007		5,949			2,400			240,218			248,567
Thereafter		1,885,934			759,913			232,277			2,878,124

		2,041,033			1,017,616			792,810			3,851,459
Unamortized (Disc.)		(12,459	)		(2,919	)		(6,899	)		(22,277	)

Total	$	2,028,574		$	1,014,697		$	785,911		$	3,829,182

* Included in NPC’s “Thereafter” amount is $188,872 of Preferred Trust Securities, reclassified to Long-Term Debt as a result of the adoption of SFAS No. 150.

** $142,180 of SPR’s Convertible Notes due 2010 that were deemed current on the June 30, 2003 Form 10Q, have been reclassified, to “Thereafter” following the shareholder vote in August 2003, which gave SPR the ability to settle the conversion of its Convertible Notes entirely in shares rather than partially in cash.

Sierra Pacific Resources

In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003, in exchange for approximately 1.3 million shares of its common stock, in two privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933.

On February 5, 2003, SPR acquired 2.1 million of Premium Income Equity Securities (PIES) including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for approximately 13.66 million shares of its common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act.

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes was used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes were used to repurchase approximately $58.5 million of SPR’s Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million was used to repay SPR’s Floating Rate Notes due April 20, 2003, and the remaining proceeds were available for general corporate purposes.

On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. Before SPR received shareholder approval, holders of the Convertible Notes were entitled to receive both shares of common stock and cash upon conversion on their notes. As a result of receiving shareholder approval, through the close of business on February 14, 2010, for each $1,000 principal amount of the Convertible Notes surrendered, SPR has the option to issue (i) 76.7073 shares of Common Stock plus an amount of cash equal to the then market value of 142.4564 shares of our Common Stock, subject to adjustment upon the occurrence of certain dilution events; or (ii) 219.1637 shares of our Common Stock, subject to adjustment upon the occurrence of certain dilution events. If the noteholders present the Convertible Notes for conversion and SPR elects to satisfy the conversion of the Convertible Notes in stock and cash, the total amount of the cash payable on conversion would be approximately $253.6 million, at an assumed five-day average closing price of $5.93 per share (based upon the last reported sale price of SPR’s common stock on November 3, 2003). The amount of cash payable on conversion of the Convertible Notes will increase as the average closing price of SPR’s common stock increases.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As a result of the shareholder approval discussed above, the conversion of the Convertible Notes may be fully satisfied by the issuance of stock at SPR’s election. As such, the portion to be settled with working capital, which was reported as current maturities of Long-Term Debt as of March 31, 2003 and June 30, 2003, has been reclassified as a long-term liability.

The Convertible Notes provide for the payment of dividends to the holders in an amount equal to any per share dividends on SPR common stock that would have been payable to the holders if the holders of the notes had converted their notes into shares of common stock at the applicable conversion rate on the record date for such dividend.

The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR’s securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders’ Convertible Notes upon a change of control. The indenture also provides for an event of default if SPR or any of its significant subsidiaries, including NPC and SPPC, fails to pay any indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable.

Nevada Power Company

On August 18, 2003, NPC issued and sold $350 million of its 9% General and Refunding Mortgage Notes, Series G, due 2013. The Series G Notes were issued with registration rights. The proceeds of the issuance were used to satisfy NPC’s obligations with respect to its $210 million 6% Notes due September 15, 2003, and its $140 million General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003.

The Series G Notes limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series G Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $25 million from the date of the issuance of the Series G Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series G Notes, NPC can meet a fixed charge coverage ratio test, and the total amount of such dividends is less than (i) the sum of 50% of NPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series G Notes, plus (ii) 100% of NPC’s aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC’s investment in certain subsidiaries.

The terms of the Series G Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, 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, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Resource Plan and certain letters of credit issued to support NPC’s obligations with respect to energy suppliers.

If NPC’s Series G Notes are upgraded to investment grade by both Moody’s and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series G Notes will be suspended and will no longer be in effect so long as the Series G Notes remain investment grade.

Among other things, the Series G Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, the holders of Series G Notes are entitled to require that NPC repurchase the Series G Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest. The Series G Notes will mature August 15, 2013.

On April 2, 1997, NVP Capital I (Trust), a wholly-owned subsidiary of NPC, issued 4,754,860, 8.2% preferred trust securities (QUIPS) at $25 per security. NPC owns all of the Series A common securities, 147,058 shares issued by the Trust for $3.7 million. The QUIPS and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the QUIPS and the common securities and using the proceeds thereof to purchase from NPC its 8.2% Junior Subordinated Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March 31, 2046, under certain conditions, in a principal amount of $122.6 million. The sole asset of the Trust is the QUIDS. Holders of the Series A QUIPS are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March,

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

June, September and December of each year. Interest payments made by NPC in respect of the QUIDS are sufficient to provide the trust with funds to pay the required cash distribution on the QUIPS and the common securities of the trust. The Series A QUIPS are subject to mandatory redemption, in whole or in part, upon repayment of the Series A QUIDS at maturity or their earlier redemption in an amount equal to the amount of related Series A QUIDS maturing or being redeemed. The QUIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption. NPC’s obligations provide a full and unconditional guarantee of the Trust’s obligations under the QUIPS. Financial statements of the Trust are consolidated with NPC’s. Separate financial statements are not filed because the Trust is wholly owned by NPC and essentially has no independent operations, and NPC’s guarantee of the Trust’s obligations is full and unconditional. The $118.9 million in net proceeds was used for general corporate utility purposes and the repayment of short-term debt.

In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of Nevada Power Company, issued 2,800,000, 7.75% Cumulative Trust Issued Preferred Securities (TIPS) at $25 per security. NPC owns the entire common securities, 86,598 shares issued by the Trust for $2.2 million. The TIPS and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the TIPS and the common securities and using the proceeds thereof to purchase from NPC its 7.75% Junior Subordinated Deferrable Interest Debentures due September 30, 2038, extendible to September 30, 2047, under certain conditions, in a principal amount of $72.2 million. The sole asset of the Trust is the deferrable interest debentures. Holders of the TIPS are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March, June, September and December of each year. Interest payments by NPC in respect of the Junior Subordinated Deferrable Interest Debentures are sufficient to provide the trust with funds to pay the required cash distributions on the TIPS and the common securities of the trust. The TIPS are subject to mandatory redemption, in whole or in part, upon repayment of the deferrable interest debentures at maturity or their earlier redemption in an amount equal to the amount of related deferrable interest debentures maturing or being redeemed. The TIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption. NPC’s obligations provide a full and unconditional guarantee of the Trust’s obligations under the TIPS. Financial statements of the Trust are consolidated with NPC’s. Separate financial statements are not filed because the Trust is wholly owned by NPC and essentially has no independent operations, and NPC’s guarantee of the Trust’s obligations is full and unconditional. The $70 million in net proceeds was used for general corporate utility purposes including the repayment of short-term debt.

As discussed in Note 1, Recent Pronouncements, NPC’s Obligated Mandatorily Redeemable Preferred Trust Securities are subject to the provisions of SFAS No. 150. The application of SFAS No. 150 resulted in the presentation of NPC’s trust preferred securities, previously reported as NPC obligated mandatorily redeemable preferred trust securities, as Long-Term Debt. NPC’s obligations, previously presented on the income statement as Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities are reported as interest charges on Long-Term Debt as of January 1, 2003.

The following table indicates the principal amount and number of shares of NPC preferred trust securities outstanding that have been reclassified as of September 30, 2003:


(Dollars in thousands)		Amount		Shares Outstanding

Preferred Trust Securities
Subject to mandatory redemption
Preferred Securities of Nevada Power Co Capital I		$	118,872		147,058
Preferred Securities of Nevada Power Co Capital III			70,000		86,598

	Total Preferred Trust Securities	$	188,872		233,656

Sierra Pacific Power Company

On May 1, 2003, SPPC’s $80 million Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest rate on the bonds was adjusted from their prior two-year 5.75% term rate to a 7.50% term rate for the period of May 1, 2003, to and including May 3, 2004. The bonds will be subject to remarketing on May 3, 2004 and will continue to be included in current maturities of Long-Term Debt. In the event that the bonds cannot be successfully remarketed on that date, SPPC will be required to purchase the outstanding bonds at a price of 100% of principal amount, plus accrued interest. From May 1, 2003, to and including May 3, 2004, SPPC’s payment and purchase obligations in respect of the bonds are secured by SPPC’s $80 million General and Refunding Mortgage Note, Series D, due 2004.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 5. Dividend Restrictions

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 may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. 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 restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below.

Nevada Power Company

First Mortgage Indenture. NPC’s first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC’s common stock and will continue to preclude payment of dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $220 million as of September 30, 2003), unless the restriction is waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. Management is currently in the process of seeking consent for the modification of this restriction. There can be no assurance that any such consent can be obtained or that any non-consenting first mortgage bonds could be redeemed or defeased prior to their stated maturity. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock.

Series E Notes and Series G Notes. NPC’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, and NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued on August 13, 2003, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s Premium Income Equity Securities (PIES)) provided that:

• those payments do not exceed $60 million for any one calendar year,

• those payments comply with any regulatory restrictions then applicable to NPC, and

• the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1.

The terms of both series of Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed: (1) under the Series E Notes, $15 million from the date of the issuance of the Series E Notes, and (2) under the Series G Notes, $25 million from the date of the issuance of the Series G Notes. In addition, NPC may make payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment:

• there are no defaults or events of default with respect to the Series E Notes or the Series G Notes,

• NPC has a ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2.0 to 1, and

• the total amount of such dividends is less than:

• the sum of 50% of NPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the applicable series of Notes, plus

• 100% of NPC’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 NPC, plus

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

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

If NPC’s Series E Notes or the Series G Notes are upgraded to investment grade by both Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s Rating Group, Inc. (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.

Accounts Receivable Facility. On October 29, 2002, NPC established an accounts receivable purchase facility, which was renewed on October 28, 2003, and will expire October 26, 2004. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC’s General and Refunding Mortgage Notes, Series E, described above.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Preferred Trust Securities. The terms of NPC’s preferred trust securities provide that no dividends may be paid on NPC’s common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures.

PUCN Compliance Order. The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC’s request for authority to issue Long-Term Debt. The PUCN order requires that, until such time as the order’s authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of September 30, 2003, NPC’s equity ratio was 36.66%. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction.

Federal Power Act. NPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is unclear, NPC believes that the Federal Power Act restriction would not be construed or applied to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts.

Enron Litigation. On November 6, 2003, the Bankruptcy Court issued an order staying execution pending appeal of the September 26, 2003 judgment entered in favor of Enron against the Utilities. One of the conditions of the stay order is that the Utilities cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations. The Utilities have the right to seek modification of the conditions of the stay if there is a material change in the facts upon which the stay order is based.

Sierra Pacific Power Company

Term Loan Agreement. SPPC’s Term Loan Agreement dated October 30, 2002, as amended, which expires October 31, 2005, limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of:

• 50% of SPPC’s Consolidated Net Income for the period commencing January 1, 2003, and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus

• the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period.

Accounts Receivable Facility. On October 29, 2002, SPPC established an accounts receivable purchase facility, which was renewed on October 28, 2003, and expires on October 26, 2004. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC’s Term Loan Agreement, described above.

Articles of Incorporation. SPPC’s Articles of Incorporation contain restrictions on the payment of dividends on SPPC’s common stock in the event of a default in the payment of dividends on SPPC’s preferred stock. SPPC’s Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock.

Federal Power Act. SPPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is unclear, SPPC believes that the Federal Power Act restriction would not be construed or applied to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 6. Earnings Per Share (SPR)

FASB Emerging Issues Task Force (EITF) Topic D-95, “Effect of Participating Convertible Securities on the Computation of Basic Earnings Per Share” (Topic D-95), requires participating securities that are convertible into common stock be included in the computation of basic earnings per share (EPS) if the effect is dilutive. The Convertible Notes are considered participating securities because the terms of the Convertible Notes include dividend participation rights. Accordingly, the provisions of Topic D-95 are applicable. Further, in computing basic EPS, Topic D-95 provides for the use of the “if-converted” method or the “two-class” method. We have elected to apply the “if-converted” method.

For the three months ended September 30, 2003, income from continuing operations and income applicable to common stock have been increased for interest expense and decreased for unrealized gain on the derivative of $4.7 million and $40 million, respectively, and 65,749,110 have been added to the weighted average number of shares outstanding, as if the notes were converted as of July 1, 2003, for the three month period ending September 30, 2003. See Note 10, Derivatives and Hedging Activities for discussion regarding the unrealized gain on the derivative. The effect of the Convertible Notes on EPS for the nine months ended September 30, 2003 is anti-dilutive and therefore excluded from the calculation of basic and diluted EPS.

The difference between Basic EPS and Diluted EPS is due to common stock equivalent shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans and the non-employee director stock plan. However, due to net losses for the nine month period ended September 30, 2003, and 2002, these items are anti-dilutive. Accordingly, Diluted EPS for these periods are computed using the weighted average shares outstanding before dilution. Common stock equivalents were determined using the treasury stock method.

The following table outlines the calculation for EPS.


			Three Months Ended					Nine Months Ended
			September 30,					September 30,

			2003			2002		2003			2002

Basic EPS
	Numerator ($000)
		Income / (Loss) from continuing operations¹	$	53,012		$	79,374	$	(92,872	)	$	(266,458	)
		Loss from discontinued operations	$	(1	)	$	—	$	(1,043	)	$	—
		Loss on disposal of subsidiary	$	(458	)	$	—	$	(6,211	)	$	—
		Cumulative effect of change in accounting principle	$	—		$	—	$	—		$	(1,566	)
		Income / (Loss) applicable to common stock¹	$	51,578		$	79,374	$	(103,051	)	$	(268,024	)
	Denominator
		Weighted average number of shares outstanding²		182,926,433			102,132,465		115,294,693			102,117,926

	Per-Share Amount
		Income / (Loss) from continuing operations	$	0.29		$	0.78	$	(0.81	)	$	(2.61	)
		Loss from discontinued operations	$	—		$	—	$	(0.01	)	$	—
		Loss on disposal of subsidiary	$	—		$	—	$	(0.05	)	$	—
		Cumulative effect of change in accounting principle	$	—		$	—	$	—		$	(0.01	)
		Income / (Loss) applicable to common stock	$	0.28		$	0.78	$	(0.89	)	$	(2.62	)

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


			Three Months Ended					Nine Months Ended
			September 30,					September 30,

			2003			2002		2003			2002

Diluted EPS
	Numerator ($000)
		Income / (Loss) from continuing operations¹	$	53,012		$	79,374	$	(92,872	)	$	(266,458	)
		Loss from discontinued operations	$	(1	)	$	—	$	(1,043	)	$	—
		Loss on disposal of subsidiary	$	(458	)	$	—	$	(6,211	)	$	—
		Cumulative effect of change in accounting principle	$	—		$	—	$	—		$	(1,566	)
		Income / (Loss) applicable to common stock¹	$	51,578		$	79,374	$	(103,051	)	$	(268,024	)
	Denominator³
		Weighted average number of shares outstanding before dilution²		182,926,433			102,132,465		115,294,693			102,117,926
		Stock options		—			—		—			—
		Executive long term incentive plan - performance shares⁴		—			—		—			—
		Executive long term incentive plan - restricted shares⁵		67,084			—		—			—
		Non-Employee Director stock plan		19,629			15,148		—			—
		Employee stock purchase plan		1,725			—		—			—
		Convertible Notes					—		—			—

		Weighted average number of shares outstanding after dilution⁶		183,014,871			102,147,613		115,294,693			102,117,926

	Per-Share Amount
		Income / (Loss) from continuing operations	$	0.29		$	0.78	$	(0.81	)	$	(2.61	)
		Loss from discontinued operations	$	—		$	—	$	(0.01	)	$	—
		Loss on disposal of subsidiary	$	—		$	—	$	(0.05	)	$	—
		Cumulative effect of change in accounting principle	$	—		$	—	$	—		$	(0.01	)
		Income / (Loss) applicable to common stock	$	0.28		$	0.78	$	(0.89	)	$	(2.62	)

Notes:

1. Income from continuing operations and income applicable to common stock for the three months ended September 30, 2003 were adjusted by adding back interest expense of $4.7 million (net of tax) and subtracting the unrealized gain on derivative of $40 million (net of tax), included in net income for the three months ended September 30, 2003.

2. Weighted average number of shares outstanding for the three months ended September 30, 2003 was adjusted by adding 65,749,110 shares for the Convertible Notes as of the beginning of the period.

3. The denominator does not include anti-dilutive stock equivalents for the Stock Option Plan and Corporate PIES due to conversion prices being higher than market prices at September 30, 2003. The amounts that would be included in the calculation if the conversion price were met would be 1.5 million shares for the Stock Option Plan and 17.3 million shares for Corporate PIES.

4. Plan terminated in 2002.

5. New plan for 2003.

6. For the nine months ended September 30, 2003 and 2002 the weighted average number of shares after dilution excludes shares of 65,814,279 and 33,004, respectively, for stock options, executive long term incentive plan — performance shares, executive long term incentive plan — restricted shares, non-employee Director stock plan, Employee stock purchase plan and convertible notes as they would be anti-dilutive.

Note 7. Segment Information (SPR)

SPR operates three business segments providing regulated electric and natural gas services. NPC provides electric service to Las Vegas and surrounding Clark County. SPPC provides electric service in northern Nevada and the Lake Tahoe area of California. SPPC also provides natural gas service in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.

Information as to the operations 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. Intersegment revenues are not material.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Financial data for business segments is as follows (in thousands):


Three Months Ended	NPC		SPPC		Total
September 30, 2003	Electric		Electric		Electric		Gas			Other		Consolidated

Operating Revenues	$	639,661	$	250,476	$	890,137	$	13,931		$	809	$	904,877

Operating Income (Loss)	$	127,737	$	32,750	$	160,487	$	(162	)	$	5,119	$	165,444


Three Months Ended	NPC		SPPC		Total
September 30, 2002	Electric		Electric		Electric		Gas			Other		Consolidated

Operating Revenues	$	712,536	$	285,720	$	998,256	$	18,473		$	642	$	1,017,371

Operating Income	$	109,183	$	30,252	$	139,435	$	(231	)	$	4,068	$	143,272


Nine Months Ended	NPC		SPPC		Total
September 30, 2003	Electric		Electric		Electric		Gas		Other			Consolidated

Operating Revenues	$	1,396,825	$	660,956	$	2,057,781	$	114,421	$	2,111		$	2,174,313

Operating Income (Loss)	$	155,634	$	44,149	$	199,783	$	4,209	$	(6,650	)	$	197,342


Nine Months Ended	NPC			SPPC		Total
September 30, 2002	Electric			Electric		Electric			Gas		Other		Consolidated

Operating Revenues	$	1,545,867		$	707,558	$	2,253,425		$	99,139	$	2,264	$	2,354,828

Operating Income (Loss)	$	(121,414	)	$	35,311	$	(86,103	)	$	4,826	$	14,326	$	(66,951	)

Note 8. Disposal and Impairment of Long-Lived Assets

e·three

SPR’s subsidiary, e·three, was organized in October 1996 to provide energy and other business solutions in commercial and industrial markets. SPR’s subsidiary, e·three Custom Energy Solutions, LLC (CES) was formed in October 1998 for the purpose of selling and implementing energy-related performance contracts and the construction and operation of a chilled water cooling plant in the downtown area of Las Vegas supplying indoor air-cooling requirements for a number of businesses in its immediate vicinity.

In keeping with management’s strategy to focus on its core utility businesses, SPR began negotiations in the second quarter of 2003 to sell e·three and CES. Accordingly, at June 30, 2003, e·three and CES were reported as discontinued operations. Based on the expected selling price, a pre-tax loss on disposal of $8.9 million was recognized for the six months ended June 30, 2003. On September 26, 2003, the sale of e·three and CES were completed. As a result of the final sales price, an additional pre-tax loss on disposal of $703,787 was recognized for the three months ended September 30, 2003. The operations of e·three and CES were included in the “Other” business segment.

Other Property Disposals

During 2002, the Utilities began pursuing the sale of several non-essential properties. As a result, on January 15, 2003, NPC sold a parcel of land located on Flamingo Road near the Barbary Coast Casino in Las Vegas, Nevada. NPC received cash proceeds of approximately $18 million for the property and retained an easement and other rights necessary to maintain aerial power lines that cross the property. Also, it was agreed that NPC will receive an additional $2.6 million from the sale if the power lines that cross the property are removed and the other rights are relinquished within a five-year period from the date of the sale. The property had been originally transferred to NPC at no cost. The transaction resulted in a gain of $17.7 million, which will be recognized into revenue over a period of three years consistent with the accounting treatment directed by the PUCN.

On July 17, 2003, NPC sold a parcel of land located on Centennial Road in North Las Vegas, Nevada. NPC received cash proceeds of approximately $4.9 million for the property. The property had a carrying value of approximately $1.2 million. The transaction resulted in an approximate gain of $3.7 million, which will be recognized into revenue over a period of three years consistent with the accounting treatment directed by the PUCN.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On August 12, 2003, NPC auctioned parcels of land located on Flamingo Road from Koval Lane to Maryland Parkway, commonly known as “the Flamingo Corridor.” The net sales price for these properties was $24.4 million. The carrying value of the properties was approximately $0.2 million. The sale closed on October 28, 2003. The transaction resulted in an approximate gain of $24.2 million, of which $2.4 million is being held in escrow pending the final outcome of related litigation. The gain will be recognized in revenue over a period of three years consistent with the accounting treatment directed by the PUCN.

On November 11, 2002, SPPC agreed to sell land located in Nevada County and Sierra County, California, commonly referred to as Independence Lake. The sale was subject to review by a third party who retained certain rights, including water rights, after the sale is completed. Also, the sales agreement included a due diligence review period of 180 days which allowed the buyer to review and accept a variety of matters agreed to by both parties. In April 2003, the buyer terminated the agreement during the review period as provided for in the agreement. SPPC plans to sell the property and is engaged in discussions with potential buyers.

Sierra Pacific Communications

In 2000, Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR, and Touch America (formerly Montana Power), formed Sierra Touch America LLC (STA), a limited liability company whose primary purpose was to engage in communications and fiber optics business projects, including construction of a fiber optic line between Salt Lake City, Utah, and Sacramento, California.

In September 2002, SPC conveyed its membership interest in STA to Touch America and obtained an indemnity for any liabilities associated with STA, all in exchange for title to several fibers in the line and a $35 million promissory note. On June 19, 2003, citing uncertainty about their liquidity, Touch America Holdings and STA filed for bankruptcy under Chapter 11 of the United States Bankruptcy Code.

In light of the bankruptcy of Touch America Holdings and STA, SPC evaluated its business to determine whether the Touch America bankruptcy has caused an impairment of SPC’s assets. SPC anticipates that the market for fiber optic cable and conduits will likely become significantly over-supplied and has recognized an impairment charge of $32.9 million during the second quarter of 2003. The asset impairment charge consisted of $14.7 million of fiber optic cable, conduits, and other related business equipment write-downs related to SPC’s metropolitan area network assets (MAN assets), and $18.2 million in fiber optic cable, conduits, and other related business equipment write-downs of its long haul network assets.

This evaluation was conducted in conformance with the guidelines of SFAS 144, and also considered factors such as the anticipated liquidation of Sierra Touch America LLC assets, resulting in significant changes in business climate and projected discounted cash flows from the assets. SPC evaluated its MAN assets using projected discounted cash flows. The evaluation factored the undiscounted cash flows from current and projected sales contracts and continued operating expenses over the approximate 18-year remaining life of the assets and then discounted those cash flows to the end of the current reporting period. SPC evaluated its long haul network assets based in part on a pending sale for a portion of the long haul network assets currently under construction and in part by prices for similar assets adjusted for the market factors that resulted from the Touch America bankruptcy discussed above.

Note 9. Regulatory Actions

Nevada Power Company 2002 Deferred Energy Case

On November 14, 2002, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requested a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments resulted in a request for an overall rate reduction of 6.3%.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The decision on this case was issued May 13, 2003, and authorized the following:

• recovery of $147.6 million, with a carrying charge, and a $48.1 million disallowance;

• a three-year amortization of the balance commencing on May 19, 2003;

• a reduction in the Base Tariff Energy Rate (BTER) to an effective non-residential rate of $0.04322 per kWh, and an effective residential rate of $0.04186 per kWh.

The new rates went into effect on May 19, 2003.

The Bureau of Consumer Protection (BCP) filed a Petition with the District Court of Clark County, Nevada, for Judicial Review of the PUCN Order on August 8, 2003, against PUCN, Case No. A471928. On September 8, 2003, the PUCN filed its answer to the BCP Petition. The PUCN response cites a number of affirmative defenses to the allegations contained in the BCP petition and asks that the court dismiss the BCP petition. The court has not ruled on this matter.

Sierra Pacific Power Company 2003 Deferred Energy Case

On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase request amounted to 0.01%. The interveners’ testimony was received April 25, 2003, and included proposed disallowances from $34 million to $76 million. Prior to the hearing that was scheduled to begin on May 12, 2003, the parties negotiated a settlement agreement. The agreement included the following provisions:

• A reduction in the current deferred energy balance of $45 million leaving a balance payable to customers of approximately $29.6 million.

• A two-year amortization of the amount payable returning one third of the balance in the first year (approximately $9.9 million), and two thirds of the balance the second year (approximately $19.7 million).

• Discontinue carrying charges on deferred energy balances that SPPC is already collecting from customers and on the $29.6 million amount payable as a result of the agreement.

• Maintain the currently effective Base Tariff Energy Rate.

• SPPC maintains the rights to claim the cost of terminated energy contracts in future deferred filings.

• Parties agreed that with the $45 million reduction the remaining costs for purchasing fuel and power during the test year were prudently incurred and are just and reasonable.

• SPPC and the BCP agreed to file a motion to dismiss the civil lawsuits filed in relation to the 2001 SPPC deferred energy case.

The agreement was approved by the PUCN at the agenda meeting held on May 19, 2003, and the new rates went into effect on June 1, 2003.

Annual Purchased Gas Cost Adjustment (SPPC)

On May 15, 2003, SPPC filed its annual application for Purchased Gas Cost Adjustment for its natural gas local distribution company. In the application, SPPC asked for an increase of $0.02524 per therm to its Base Purchased Gas Rate (BPGR) and a Balancing Account Adjustment (BAA) credit to customers of $0.04833 per therm to be amortized over two years. This request would result in a decrease of approximately 5% in customer rates.

NOTE 10. Derivatives and Hedging Activities (SPR, NPC, SPPC)

SPR, NPC, and SPPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

SPR’s and the Utilities’ objective in using derivatives is to reduce exposure to energy price risk and interest rate 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 include forwards, options, and swaps. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

At September 30, 2003, the fair value of the derivatives resulted in the recording of $37 million, $21 million and $16 million in risk management assets and $41 million, $14 million and $27 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. 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. Accordingly, at September 30, 2003, $32 million, $5 million and $26 million in net risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In addition, for the nine months ended September 30, 2003, the unrealized gains and losses resulting from the change in the fair value of derivatives designated and qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other Comprehensive Income. Such amounts are reclassified into earnings when the related transactions are settled or terminate. Accordingly, the remaining $1.5 million relating to SPR’s terminated interest rate swap was reclassified into earnings during the nine months ended September 30, 2003.

The effects of SFAS No. 133 on comprehensive income and the components thereof at September 30, 2003, and 2002, are as follows (in thousands):


	SPR			NPC			SPPC

Net Income (Loss) for the nine months ended September 30, 2003	$	(103,051	)	$	25,086		$	(27,199	)
Change in market value of risk management assets and liabilities as of September 30, 2003, net of taxes of $940, $70, and $33, respectively		1,746			130			61

Total Comprehensive Income (Loss) for the nine months ended September 30, 2003	$	(101,305	)	$	25,216		$	(27,138	)

Net (Loss) for the nine months ended September 30, 2002	$	(268,024	)	$	(216,025	)	$	(12,389	)
Change in market value of risk management assets and liabilities as of September 30, 2002, net of taxes of $1,468, ($217), and ($103), respectively		2,726			(403	)		(191	)

Total Comprehensive (Loss) for the nine months ended September 30, 2002	$	(265,298	)	$	(216,428	)	$	(12,580	)

In connection with SPR’s issuance of its Convertible Notes on February 14, 2003, (see Note 4, Long-Term Debt), the conversion option, which is treated as a cash-settled written call option, was separated from the debt and accounted for separately as a derivative instrument in accordance with EITF Issue No. 90-19, “Convertible Bonds with Issuer Option to Settle for Cash upon Conversion.” Upon issuance, the fair value of the option was recorded as a current liability in Other Current Liabilities. The change in the fair value was recognized in earnings in the period of the change.

EITF Issue No. 00-19 of the Emerging Issues Task Force of the FASB (“EITF”), “Accounting for Derivative Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock” provides for the recording of the fair value of the derivative in equity, if all of the applicable provisions of EITF Issue No. 00-19 are met. Management believes that all such applicable provisions have been met. Accordingly, the fair value of the derivative, $118 million on the date of the shareholder vote, was reclassified to equity. The fair value of the option was determined using the closing stock price of $4.68 as of August 11, 2003, the strike price for conversion of $4.5628, a measurement for the volatility of the stock price and the time value of money. The valuation resulted in an unrealized pre-tax gain of $61.5 million for the quarter ended September 30, 2003. The valuations for the quarters ended March 31, 2003, and June 30, 2003, resulted in a pre-tax gain of $15.9 million in the first quarter and a pre-tax loss of $123.5 million respectively. The net impact of these valuation adjustments was an unrealized pre-tax loss of $46.1 million for the nine months

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

ended September 30. EITF Issue No. 00-19 also provides that subsequent changes in fair value should not be recognized as long as the derivative remains classified in equity.

Note 11. Commitments and Contingencies

Environmental

Nevada Power Company

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 controls is $1.2 billion. As a 14% owner in Mohave, NPC’s cost could be $168 million.

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

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.

Because of the coal and water supply issues at Mohave, NPC is preparing for the shutdown of the facility by the end of 2005. In July, NPC filed an Integrated Resource Plan with the PUCN, that assumed 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 net book value of $36.1 million. Alternatively, NPC requested that the PUCN authorize the transfer of the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN.

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. NDEP is expected to identify remediation requirements for the contaminated groundwater that resulted from the evaporation ponds by the end of 2003. New pond construction and lining costs, which will be capitalized, are estimated to cost approximately $25 million, of which, $17 million is expected to be spent by the end of 2003.

At the Reid Gardner Station, the NDEP determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required NPC to submit a corrective action plan. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system commenced operation in October 2003.

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. If the EPA requires remediation, capital expenditures and temporary outages of two of Clark Station’s generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. On October 31, 2003, the EPA issued a Notice of Violation and Finding of Violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC is expected to occur before the end of 2003. The conference will enable NPC to present evidence on the nature and finding of violations and any efforts which NPC has taken or proposes to take to achieve compliance. Monetary penalties for the violation have not been determined.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On February 25, 2003, NPC submitted its 2002 Phase II Annual Certification Report to the EPA in accordance with the EPA’s Acid Rain Program. NPC indicated that its Reid Gardner Unit 1 may be in violation with the EPA’s annual NOx emission rate for wall-fired boilers. In July 2003, the EPA concurred with the Company’s submission and the company paid $134,000 for excess emissions.

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 now has a reclamation estimate supported by a bond of $4.8 million with the Utah Division of Oil and Gas Mining. The property was leased in August 2002 with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond. However, this lease has expired and is not expected to be renewed.

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 PRPs formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and 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. SPPC recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through September 30, 2003. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and revise, if necessary, its recorded liability for the Sites.

Lands of Sierra

LOS, a wholly-owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contamination resulting from an underground fuel tank that was removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. On February 3, 2003, the Lahontan Regional Water Quality Control Board re-opened closure of this property. SPR is completing the evaluation of alternative remediation technologies and their effectiveness in reducing contamination at this site. An application for closure will be re-submitted at that time. Additional remediation costs are expected to be approximately $100,000.

Litigation Contingencies

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC. The Utilities intend to appeal the Judgment of the Bankruptcy Court to the U.S. District Court of New York.

Nevada Power Company

In June 2003, El Paso Merchant Energy demanded mediation of its claim for a termination payment arising out of El Paso’s September 25, 2002, termination of all executory purchase power contracts between NPC and El Paso. El Paso claims that under the terms of the contracts, NPC owes El Paso approximately $39 million representing the difference between the contract price and the market price for power to be delivered under all the terminated contracts and the amount remaining unpaid under the contracts for power delivered between May 2002 and October 2002. NPC claims that El Paso owes NPC an amount up to approximately $162 million for undelivered power representing the difference between the replacement price or market price for power to be delivered under all the executory contracts and the contract price for that power. The mediation was unsuccessful, and on July 25, 2003, NPC commenced an action against El Paso Merchant Energy and several of its affiliates in the Federal District Court for the District of Nevada for damages resulting from breach of these purchase power contracts. That action has not yet been served on El Paso and the issues have not been joined.

On May 3, 2002, and July 3, 2002, respectively, Reliant Resources (Reliant) and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002, and July 30, 2002, Reliant and Idaho asserted claims for $25.6 million and $8.9 million, respectively, under the Western System Power Pool Agreement (WSPP) for liquidated damages under energy contracts that each company terminated before the delivery dates of the power. Such claims are subject to mandatory mediation and, in some cases, arbitration under the contracts. Disputes between Idaho and Reliant were both mediated to conclusion without reaching a settlement. In May 2003, Idaho filed suit against NPC in Idaho state court claiming damages in the approximate amount of $8.9 million dollars. NPC has moved to dismiss the complaint on jurisdictional grounds and filed its own action in Nevada for declaratory relief claiming that it does not owe Idaho any money under the terminated contracts. The actions are currently in the pleading stage and NPC’s motion to dismiss is scheduled to be heard in the fourth quarter. NPC continues to have discussions with Reliant on a broad range of issues including whether any money is owed Reliant under the purchased power contracts. Neither party has filed any action arising out of this dispute.

On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG requested that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claimed that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC’s contract claims and defenses. In March 2003, the arbitrator overseeing the arbitration proceedings dismissed MSCG’s demand for arbitration and agreed that the issues raised by MSCG were not calculation issues subject to arbitration and that NPC’s contract defenses were likewise not arbitrable.

NPC filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada asking the Court to declare that NPC is not liable for any damages as a result of MSCG’s termination of its power supply contracts. On April 17, 2003, MSCG answered the complaint and filed a counterclaim against NPC at the FERC alleging non-payment of the termination payment in the amount of $25 million. In April 2003 MSCG also filed a complaint against NPC at FERC alleging that NPC should be required to pay MSCG the amount of the claimed termination payment pending resolution of the case. NPC filed a motion to intervene in the

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

FERC action commenced by MSCG and FERC dismissed MSCG’s complaint. NPC is unable to predict the outcome of the District Court complaint.

In connection with claims by their terminated energy suppliers, the Utilities have established reserves, included in their Consolidated Balance Sheets in “Contract termination reserves,” of approximately $279 million and $105 million as of September 30, 2003, for NPC and SPPC, respectively. Also, pursuant to the deferred energy accounting provisions of AB 369, NPC and SPPC added approximately $245 million and $84 million, respectively, to their deferred energy balances for recovery in rates in future periods associated with terminated supplier claims. The amounts deferred differ from the contract termination reserves because of payments which have reduced the reserves and because the reserves include amounts not subject to deferred energy accounting.

Regulatory Contingencies

The Utilities’ rates are currently subject to the approval of the PUCN and, in the case of SPPC, they are also subject to the approval of California Public Utility Commission (CPUC) and are designed to recover the cost of providing generation, transmission, and distribution services. As a result, the Utilities qualify for the application of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” issued by the Financial Accounting Standards Board (FASB). This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management regularly assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and the status of any pending or potential deregulation legislation. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1 in Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2002, management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge or expensed in current period earnings.

Regulatory Accounting affects Deferred Energy, Goodwill and Merger Costs, Generation Divestiture Costs, and Piñon Pine, all of which are discussed immediately below. To the extent that the Utilities may not be permitted to recover any portion of deferred energy, goodwill and merger costs, generation divestiture costs and long-lived assets (Piñon Pine), the disallowed costs and related carrying charges would be required to be written off in current period earnings. A significant disallowance of these costs by the PUCN would have a material adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Deferred Energy

Nevada and California statutes permit regulated utilities to, from time-to-time, adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect of fluctuations in the cost of purchased gas, fuel, and purchased power.

On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369, include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities implemented deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review.

AB 369 requires the Utilities to file applications to clear their respective deferred energy account balances at least every 12 months and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances. Deferred energy balances subject to PUCN review as of September 30, 2003 are $338 million and $124 million for NPC and SPPC, respectively, including contract termination costs.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Goodwill and Merger Costs

The order issued by the PUCN in December 1998 approving the merger of SPR and NPC directed both NPC and SPPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order specifically directed both Utilities to defer merger transaction costs, transition costs, and goodwill costs for a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs the Utilities to propose an amortization period for the merger costs and allows the Utilities to recover the costs to the extent they are offset by merger savings.

Costs deferred as a result of the PUCN order were $331.2 million of goodwill and $63.4 million in other merger costs as of September 30, 2003. The deferred other merger costs consist of $41.5 million of transaction and transition costs and $21.9 million of employee separation costs. Employee separation costs were comprised of $17.4 million of employee severance, relocation, and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains. NPC has requested recovery of these costs in its General Rate Case filed October 1, 2003. SPPC expects to request recovery of these costs in its General Rate Case to be filed December 1, 2003.

Accounting for Generation Divestiture Costs

As a condition to its approval of the merger between SPR and NPC, the Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture Plan stipulation for the sale of the Utilities’ generation assets. In May 2000, an agreement was announced for the sale of NPC’s 14% undivided interest in the Mohave Generating Station (Mohave). In the fourth quarter of 2000, the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies.

The sales agreements for the six bundles provided that they would terminate eighteen months after their execution, and all of the agreements have now terminated in accordance with their respective provisions. As of September 30, 2003, NPC and SPPC had incurred costs, including carrying charges, of approximately $21.4 million and $13.0 million, respectively, in order to prepare for the sale of generation assets. In the fourth quarter of 2001, each Utility requested recovery of its respective costs in its application for a general rate increase filed with the PUCN. In 2002, the PUCN delayed recovery of divestiture costs to future rate case requests and granted a carrying charge on the costs until such time as recovery is allowed. NPC has requested recovery of these costs in its General Rate Case filed October 1, 2003. SPPC expects to request recovery of these costs in its General Rate Case to be filed December 1, 2003.

Piñon Pine

As discussed in more detail in Note 21, Piñon Pine, of Notes to Financial Statements in SPR’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, SPPC owns a combined cycle generation facility, a post-gasification facility, and, through its wholly owned subsidiaries, owns a gasifier that are collectively referred to as the Piñon Pine Power Project (Piñon Pine). Construction of Piñon Pine was completed in June 1998. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $97 million as of September 30, 2003.

To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001, SPPC retained an independent engineering consulting firm to complete a comprehensive study of the Piñon Pine gasification plant. After evaluating the options presented in the draft report, SPPC decided not to pursue modifications intended to make the facility operational and intends to seek recovery, net of salvage, through regulated rates in its next general rate case to be filed by December 1, 2003, based, in part, on the PUCN’s approval of Piñon Pine as a demonstration project in an earlier resource plan.

Note 12. Subsequent Events

See Notes 1, 3, 8 and 11 for discussion of events occurring after September 30, 2003.

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) a requirement to pay the judgment entered by the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron for payments allegedly due under terminated purchase power contracts, or to provide additional cash collateral for the judgment pending appeal;

(2) unfavorable rulings in rate cases to be filed by NPC and SPPC (the Utilities) with the Public Utilities Commission of Nevada (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;

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

(4) whether NPC’s ability to pay SPR dividends will be restored in the near future, and whether SPPC will be able to continue to pay SPR dividends under the terms of SPPC’s financing agreements and/or restated articles of incorporation;

(5) whether suppliers, other than Enron, which have terminated their power supply contracts with NPC and/or SPPC will be successful in pursuing their claims against the Utilities for liquidated damages under their power supply contracts;

(6) whether the PUCN will issue favorable orders in a timely manner to permit the Utilities to borrow money and issue additional securities to finance the Utilities’ operations, and to purchase power and fuel necessary to serve their respective customers, and to repay maturing debt;

(7) whether SPR, NPC, and SPPC will be able to maintain sufficient stability with respect to their liquidity and relationships with suppliers to be able to continue to operate outside of bankruptcy;

(8) whether current suppliers of purchased power, natural gas, or fuel to NPC or SPPC will continue to do business with NPC or SPPC or will terminate their contracts, particularly in the event of a ratings downgrade and whether NPC or SPPC will have sufficient liquidity to pay its respective power requirements if their current suppliers continue to require the Utilities to make pre-payments or more frequent payments on their power purchases;

(9) whether the Utilities will need to purchase additional power on the spot market to meet unanticipated power demands (for example, due to unseasonably hot weather) and whether suppliers will be willing to sell such power to the Utilities in light of their weakened financial condition;

(10) whether SPPC will be successful in obtaining PUCN approval to recover the costs of the gasifier facility at the Piñon Pine Power Project in a future general rate case;

(11) whether NPC and SPPC will be successful in obtaining PUCN approval to recover goodwill and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

(12) 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;

(13) 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;

(14) whether the Utilities will be able, either through appeals of the Federal Energy Regulatory Commission (FERC) proceedings or negotiation, to obtain lower prices on the long-term purchased power contracts that they entered into during 2000 and 2001 that are priced above current market prices for electricity;

(15) 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;

(16) unseasonable weather and other natural phenomena which, in addition to impacting 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;

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

(18) the loss of any significant customers;

(19) 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;

(20) 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;

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

(22) future economic conditions, including inflation or deflation rates and monetary policy;

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

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

(25) 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.

Critical Accounting Policies

The following items represent critical accounting policies that under different conditions or using different assumptions could have a material effect on the financial position and results of operations of SPR and the Utilities:

Regulatory Accounting

Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Goodwill and Merger Costs, Accounting for Generation Divestiture Costs, Disposal of and Impairment of Long-Lived Assets, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below.

Deferred Energy Accounting

On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369 (AB 369). The provisions of AB 369 include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities implemented deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances.

The Utilities are exposed to commodity price risk primarily related to changes in the market price of electricity as well as changes in fuel costs incurred to generate electricity. See Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in SPR’s, NPC’s, and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2002, for a discussion of the Utilities’ purchased power procurement strategies, and Commodity Price Risk and commodity risk management program. As discussed above, deferred energy accounting facilitates the recovery of costs incurred to procure fuel and purchased power for NPC and SPPC.

As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Nevada Power Company 2001 Deferred Energy Case, in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, on November 30, 2001, NPC filed an application with the PUCN seeking to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001, and September 30,

2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, disallowing $434 million of deferred purchased fuel and power costs, and allowing NPC to collect the remaining $478 million over three years beginning April 1, 2002. As a result of this disallowance, NPC wrote off $465 million of deferred energy costs and related carrying charges, the two major national rating agencies immediately downgraded the credit rating on SPR’s, NPC’s, and SPPC’s debt securities (followed by further downgrades late in April 2002), and the market price of SPR’s common stock fell substantially.

On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances of $195.7 million for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On May 12, 2003, the PUCN issued its decision on NPC’s deferred energy application, disallowing $48.1 million of deferred purchased fuel and power and related carrying costs, and allowing NPC to collect the remaining $147.6 million over three years beginning May 19, 2003. As a result of this decision, NPC wrote off $48.1 million of disallowed deferred energy costs and related carrying charges in May 2003.

As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Sierra Pacific Power Company 2002 Deferred Energy Case, in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, SPPC filed an application with the PUCN seeking to establish a DEAA rate to clear its deferred balances for purchased fuel and power costs accumulated between March 1, 2001, and November 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. On May 28, 2002, the PUCN issued its decision on SPPC’s deferred energy application, disallowing $53 million of deferred purchased fuel and power costs, and allowing SPPC to collect the remaining $150 million over three years beginning June 1, 2002. As a result of this decision, SPPC wrote off $58 million of disallowed deferred energy costs and related carrying charges in the second quarter of 2002.

On January 14, 2003, SPPC filed an application with the PUCN that sought to clear deferred balances of $15.4 million for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002. The application sought to establish a DEAA rate to repay accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. On May 19, 2003, the PUCN approved a stipulated agreement between SPPC and the staff of the PUCN and others that resulted in a rate decrease of $9.9 million beginning June 1, 2003, and a rate decrease of $19.7 million beginning June 1, 2004. As a result of the agreement, SPPC reduced its deferred energy balance by $45 million, from a balance of approximately $15.4 million collectible from customers to a balance of approximately $29.6 million payable to customers. This resulted in a write off of $45 million in May 2003.

Both Utilities continue to be entitled under AB 369 to utilize deferred energy accounting for their electric operations and both Utilities continue to accumulate amounts in their deferral of energy costs accounts. Because of contracts entered into during the Western energy crisis in 2001 to assure adequate supplies of electricity for their customers, the Utilities incurred fuel and purchased power costs in excess of amounts they were permitted to recover in current rates.

Accounting for Goodwill and Merger Costs

The extent to which goodwill and merger costs will be recovered in future revenues and the timing of those recoveries is expected to be determined in general rate cases filed in the third and fourth quarters of 2003 by NPC and SPPC, respectively. To the extent that the Utilities are not permitted to recover any portion of goodwill in future rates, the amount not recoverable will be reviewed for impairment and accounted for under the provisions of Statement of Financial Accounting Standard (SFAS) No. 142, “Goodwill and Other Intangible Assets”. A significant disallowance of goodwill or merger costs by the PUCN would have a material adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Accounting for Generation Divestiture Costs

AB 369, which was signed into law on April 18, 2001, prohibited the sale of generation assets until July 2003 and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits any further divestiture of generation properties by California utilities until 2006, including SPPC, and could also affect any sale of NPC’s interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison. SPPC’s request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied. In September 2002, the California Legislature approved an exemption to AB 6, which had prevented private utilities from selling any power plants that provide energy to California customers until 2006. The exemption allows SPPC to complete the sale of the hydroelectric units to Truckee Meadows Water Authority (TMWA) subject to review and approval of the sale by the CPUC.

The sales agreements for the six bundles provided that they would terminate eighteen months after their execution, and all of the agreements have now terminated in accordance with their respective provisions. As of September 30, 2003, NPC and SPPC had incurred costs, including carrying charges, of approximately $21.4 million and $13.0 million, respectively, in order to prepare for the sale of generation assets. In the fourth quarter of 2001, each Utility requested recovery of its respective costs in its application for a general rate increase filed with the PUCN. In 2002, the PUCN delayed recovery of divestiture costs to future rate case requests and granted a carrying charge on the costs until such time as recovery is allowed. To the extent that the Utilities may not be permitted to recover any portion of these costs in future rates, the disallowed costs and related carrying charges would be required to be written off in current period earnings.

Disposal of and Impairment of Long-Lived Assets

SPR and the Utilities evaluate their Utility Plant and definite-lived tangible assets for impairment whenever indicators of impairment exist. Accounting standards require that if the sum of the undiscounted expected future cash flows from a company’s asset (without interest charges that will be recognized as expenses when incurred) is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset.

Sierra Pacific Communications

As discussed in Note 8, Disposal and Impairment of Long-Lived Assets, Sierra Pacific Communication (SPC) operates its telecommunication business in two segments, Metropolitan Area Network and Long Haul Fiber Network. SPC evaluated the assets of its business as of June 30, 2003, as a result of market conditions created by the bankruptcy of Touch America. This event

substantially deteriorated the telecommunications market in the areas where SPC operates its long haul fiber assets. SPC anticipates the market for fiber optic cable and conduits will likely become significantly over-supplied which has caused Sierra Pacific Communications to test for, and as a result, recognize an impairment charge. Estimates underlying the asset impairment are significant in determining the impairment charge. The assumptions underlying the calculation of the undiscounted future cash flows used to evaluate the impairment, including projected revenues and expenses and the discount rate used to present value future cash flows materially effect the amount of the impairment charge. In estimating undiscounted future cash flows for its long haul fiber assets, SPC used prices for similar asset sales adjusted for the markets factors that resulted from the Touch America bankruptcy discussed above. To estimate the undiscounted cash flows from the metropolitan area network assets, SPC used revenues from current and projected sales contracts and continued operating expenses over the approximate 18-year remaining life of the assets. Any difference from the assumptions used could materially change the results of the asset impairment charge as recognized in the current period.

Piñon Pine

Mohave

As discussed in more detail in Note 11, Commitments and Contingencies, Environmental, NPC owns a 14% interest in the Mohave Generating Station located in Laughlin, Nevada. Included in the Consolidated Balance Sheets of SPR and NPC is the net book value of NPC’s share of the Mohave facility, which is approximately $36.1 million as of September 30, 2003.

Due to a lack of progress in negotiations with the parties to resolve several coal and water supply issues, Southern California Edison (SCE), the operating partner, filed an application with the California Public Utility Commission (CPUC) to determine whether it is in the public interest to continue operation of the Mohave facility beyond 2005. Also, 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 uncertainty over the coal supply and water issues.

Because of the coal and water supply issues at Mohave, NPC is preparing for the shutdown of the facility by the end of 2005. In July, NPC filed an Integrated Resource Plan with the PUCN, that 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 in order to recover the remaining book value of Mohave. Alternatively, NPC requested that the PUCN authorize the transfer of the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN. However, if NPC is unsuccessful in obtaining recovery, there could be an adverse effect on NPC’s and SPR’s financial position, results of operations, and cash flows.

e·three and e·three Custom Energy Solutions

SPR’s subsidiary, e·three, was organized in October 1996 to provide energy and other business solutions in commercial and industrial markets. SPR’s subsidiary, e·three Custom Energy Solutions, LLC (CES), was formed in October 1998 for the purpose of selling and implementing energy-related performance contracts and the construction and operation of a chilled water cooling plant in the downtown area of Las Vegas supplying indoor air-cooling requirements for a number of businesses in its immediate vicinity.

In keeping with management’s strategy to focus on its core utility businesses, SPR began negotiations in the second quarter of 2003 to sell e·three and CES. Accordingly, at June 30, 2003, e·three and CES were reported as discontinued operations. Based on the expected selling price, a pre-tax loss on the disposal of $8.9 million was recognized for the six months ended June 30, 2003. On September 26, 2003, the sale of e·three and CES was completed. As a result of the final sales price, an additional pre-tax loss of $703,787 from disposal was recognized for the three months ended September 30, 2003.

Accounting for Derivatives and Hedging Activities

SPR, NPC, and SPPC 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 and measure those instruments at fair value.

Fuel and Purchased Power Contracts

In order to manage loads, resources, and energy price risk, the Utilities buy fuel and power under forward contracts. In addition to forward fuel and power purchase contracts, the Utilities also use options and swaps to manage price risk. All of these instruments are considered to be derivatives under SFAS No. 133. The risk management assets and liabilities recorded in the balance sheets of the Utilities and SPR are primarily comprised of the fair value of these forward fuel and power purchase contracts and other energy related derivative instruments.

Fuel and purchased power costs are subject to deferred energy accounting. Accordingly, the energy related risk management assets and liabilities and the corresponding unrealized gains and losses (changes in fair value) are offset with a regulatory asset or liability rather than recognized in the statements of operations and comprehensive income. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized if they are currently recoverable or deferred if they are recoverable or payable through future rates.

The fair values of the forward contracts and swaps are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model that incorporates assumptions such as the underlying commodity’s forward price curve, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the instruments.

Debt Conversion Option

In connection with SPR’s issuance of its Convertible Notes the conversion option, which is treated as a cash-settled written call option, was separated from the debt and accounted for separately as a derivative instrument in accordance with EITF Issue No. 90-19, “Convertible Bonds with Issuer Option to Settle for Cash upon Conversion.” Upon issuance, the fair value of the option was recorded as a current liability in Other Current Liabilities. The change in the fair value was recognized in earnings in the period of the change.

Issue No. 00-19 of the Emerging Issues Task Force of the FASB (“EITF”), “Accounting for Derivative Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock,” provides for the recording of the fair value of the derivative in equity, if all applicable provisions of EITF Issue No. 00-19 are met. On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes, which allows for the Company to choose net-cash settlement or settlement in shares upon conversion of the Convertible Notes. In accordance with EITF Issue No. 00-19, the fair value of the derivative of $118 million previously recorded in current liabilities was reclassified to equity on the date of the shareholder vote. In addition, EITF Issue No. 00-19 indicates that subsequent changes in fair value should not be recognized as long as the derivative remains classified in equity. As long as the derivative remains classified in equity, SPR will not mark this instrument to market. Accordingly, no unrealized gains or losses will be recorded in earnings subsequent to August 11, 2003. The previous changes in fair value of the derivative instrument recorded in earnings will not be reversed.

Based on the closing price of SPR’s common stock at August 11, 2003, of $4.68, the fair value of the conversion option was determined to be approximately $118 at August 11, 2003, and as a result, SPR recorded an unrealized gain of approximately $61.5 million in the quarter ended September 30, 2003. SPR recorded a cumulative net unrealized loss of approximately $46.1 million for the nine month period ending September 30, 2003.

Other Derivatives

SPR and the Utilities have other non-energy related derivative instruments. The changes in fair values of these non-energy related derivatives are reported in Other comprehensive income until the related transactions are settled or terminate, at which time the amounts are reclassified into earnings.

Environmental Contingencies

SPR and its subsidiaries are subject to federal, state, and local regulations governing air and water quality, hazardous and solid waste, land use, and other environmental considerations. Nevada’s Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation, or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air and water quality, solid, hazardous, and toxic waste.

SPR and its subsidiaries are subject to rising costs that result from a steady increase in the number of federal, state, and local laws and regulations designed to protect the environment. These laws and regulations can result in increased capital, operating, and other costs as a result of compliance, remediation, containment, and monitoring obligations, particularly with laws relating to power plant emissions. In addition, SPR or its subsidiaries may be a responsible party for environmental clean up at a site identified by a regulatory body. The management of SPR and its subsidiaries cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. SPR and its subsidiaries accrue for environmental costs only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs.

Note 11, Commitments and Contingencies, of Condensed Notes to Consolidated Financial Statements discusses the environmental matters of SPR and its subsidiaries that have been identified, and the estimated financial effect of those matters. To the extent that (1) actual results differ from the estimated financial effects, (2) there are environmental matters not yet identified for which SPR or its subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through future rates the costs to remediate such environmental matters, there could be a material adverse effect on the financial condition and future liquidity and results of operations of SPR and its subsidiaries.

Litigation Contingencies

Note 11, Commitments and Contingencies, of Condensed Notes to Consolidated Financial Statements discusses the significant legal matters of SPR and its subsidiaries. As described in Note 11, NPC and SPPC established reserves, included in their Consolidated Balance Sheets as “Contract termination reserves,” for amounts claimed for liquidated damages for terminated power supply contracts and for power previously delivered to the Utilities by Enron and other suppliers. Correspondingly, pursuant to the deferred energy accounting provisions of AB 369, NPC and SPPC added as of September 30, 2003, approximately $245 million and $84 million, respectively, to their deferred energy balances for recovery in rates in future periods associated with these terminated supplier claims. If NPC and SPPC receive unfavorable rulings with respect to the terminated supplier claims and as a result are required to pay part or all of the amounts reserved, the Utilities will pursue recovery of the amounts 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 adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

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 has had or, in the opinion of management, is expected to have, a significant impact on its financial position or results of operations.

Defined Benefit Plans and Other Postretirement Plans

As further explained in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2002, SPR maintains a pension plan as well as other postretirement benefit plans that provide health and life insurance for retired employees. All employees are eligible for these benefits if they reach retirement age while still working for SPR or its subsidiaries. These costs are determined in accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” and ultimately collected in rates billed to customers. The amounts funded are then used to meet benefit payments to plan participants. In the first nine months of 2003, SPR has contributed approximately $31.9 million and $0.1 million to the pension and other postretirement plans, respectively. For the year ended December 31, 2002, SPR contributed $41.1 million to its pension plan, and $0.2 million to the other postretirement benefits plan. Due to the sharp decline in United States equity markets since the third quarter of 2000, the value of a significant portion of the assets held in the plans’ trusts to satisfy the obligations of the plans has decreased significantly. As a result, additional contributions may be required in the future to meet the requirements of the plan to pay benefits to plan participants.

Pension Plans

SPR’s reported costs of providing non-contributory defined pension benefits (described in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

For example, pension costs are impacted by actual employee demographics (including age and employment periods), the level of contributions SPR makes to the plan, and earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

SPR made no changes to pension plan provisions in 2002 or 2003 that had a significant impact on recorded pension amounts. SPR reduced the discount rate used in determining pension expense for the calendar year 2003 from 7.5% to 6.75%. This change will not have a significant impact on reported pension costs for 2003. Additionally, SPR anticipates further reducing the discount rate in 2004. However, pension costs for 2004 are not expected to increase significantly as a result of the change in the discount rate, because of an improvement during 2003 in the market value of the plans assets.

SPR’s pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.

In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of SPR’s plan assets has been affected by sharp declines in equity markets since the third quarter of 2000.

Pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets.

Other Postretirement Benefits

SPR’s reported costs of providing other postretirement benefits (described in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

For example, other postretirement benefit costs are impacted by actual employee demographics (including age and employment periods), the level of contributions made to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plan may also impact current and future other postretirement benefit costs. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs.

SPR has made no changes to other postretirement benefit plan provisions in 2002 or 2003 that have had any significant impact on recorded benefit plan amounts. SPR reduced the discount rate used in determining other postretirement expense for the calendar year 2003 from 7.5% to 6.75%. This change will not have a significant impact on reported other postretirement benefit costs for 2003. Additionally, SPR anticipates further reducing the discount rate in 2004. This change is not expected to have a significant impact on reported other postretirement benefit costs in 2004. However, in determining the other postretirement benefit obligation and related cost, these assumptions can change from period to period, and such changes could result in material changes to such amounts.

SPR’s other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded other postretirement benefit costs.

In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of the SPR’s plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. Also, other postretirement benefit cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets.

Cost Capitalization Policies

The Utilities continue to devote substantial resources in 2003 on the Centennial Transmission project at NPC and the Falcon to Gonder Transmission project at SPPC. In addition, certain operating units of the Utilities are charged with maintaining, repairing and replacing components of generation, transmission, and distribution systems both on a scheduled basis and on an as-needed basis. As described in Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, the cost of additions, including betterments and replacements of units of property, is charged to utility plant. When units of property are replaced, renewed, or retired, their cost, plus removal or disposal costs less salvage, is charged to accumulated depreciation. Certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity as prescribed by Generally Accepted Accounting Principles (GAAP) and the FERC’s Uniform System of Accounts.

The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement, and post employment benefits, vacations, and payroll taxes; and an allowance for funds used during construction (AFUDC). The level of indirect construction overhead costs capitalized by the Utilities is based upon real-time construction activity. Accordingly, payroll and other costs capitalized will fluctuate based upon seasonal construction activities and the deployment of resources to those efforts. During periods of higher maintenance levels, these payroll and other costs will not be capitalized. As such, operating income could be impacted by the manner in which payroll and related costs are deployed. However, the total cash flow of the Utilities is not impacted by the allocation of these costs to various construction or maintenance activities.

During the three and nine months ended September 30, 2003, NPC and SPPC capitalized approximately $.85 million, $1.7 million, $4.1 million, and $4.2 million, respectively, of AFUDC as a result of construction activity. Similarly, during the three and nine months ended September 30, 2002, NPC and SPPC capitalized approximately ($54,000), $684,000, $2.4 million and $1.5 million, respectively, of AFUDC. These amounts are non-cash components reflected in the Consolidated Statements of Operations. Recognition of AFUDC as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices permit the Utility to earn a return on, and recover in rates, all capital costs charged for Utility services.

Depreciation Expense

The Utilities have a significant investment in electric plant. SPPC also has an investment in gas distribution plant. Depreciable assets of generation, transmission, and distribution operations represent approximately 91% of the Utilities’ investment in utility plant. As described in Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2002, the Utilities depreciate these assets utilizing a composite rate, which currently includes a component for net negative salvage. These assets are depreciated on a straight-line basis over the remaining useful life of the related assets, which approximates the anticipated physical lives of these assets in most cases. The Nevada Administrative Code requires the Utilities to provide a depreciation study every four years in order to substantiate the remaining physical lives of their investment in utility plant. Adjustments to the estimated depreciable lives of the Utilities’ plant are recorded on a prospective basis, as prescribed by GAAP and the FERC’s Uniform System of Accounts.

Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the PUCN or the FERC and, in the case of SPPC’s California operations, the CPUC, which also approves any changes SPPC may make to depreciation rates utilized for this property. Because the Utilities’ periodic depreciation expense is included as a component of the revenue requirement utilized in the development of the Utilities’ tariff rates, revenue reflects collection of the recognized depreciation expense. Accordingly, the impact of depreciation on net income is not significant. However, operating cash flows are positively affected by the amount of depreciation collected in rates, since depreciation expense is not a current cash outlay for the Utilities.

Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes written, or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003.

Prior to adopting SFAS 143, costs for removal of most utility assets were accrued as an additional component of depreciation expense. Under SFAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost.

Management’s methodology to assess its legal obligation included an inventory of assets by system and components, and a review of right of ways and easements, regulatory orders, leases, and federal, state, and local environmental laws. Management assumed in determining its Asset Retirement Obligations that transmission, distribution, and communications systems will be operated in perpetuity and would continue to be used or sold without land remediation; and mass asset properties that are replaced or retired frequently would be considered normal maintenance.

Management has identified a legal obligation to retire generation plant assets specified in land leases for NPC’s jointly-owned Navajo generating station. The land on which the Navajo generating station resides is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Although the related retirement obligation and corresponding charges recognized were immaterial to the financial statements of NPC, those amounts were based on certain estimates and assumptions. The estimated liability is based on two levels of decommissioning, minimal and full, and two possible retirement dates. The liability is escalated using average historical Consumer Price Index inflation factors equal to the estimated retirement dates. The liability is discounted using credit-adjusted risk-free rates of return for the respective retirement dates. Changes to future statements of financial position and results of operations will occur to the extent that actual results differ from the estimates and assumptions used, including changes in decommissioning costs, timing, or changes in NPC’s credit rating. SPPC has no significant asset retirement obligations.

The Utilities have various transmission and distribution lines as well as substations that operate under various rights of way that contain end dates and restorative clauses. Management operates the transmission and distribution system as though they will be operated in perpetuity and will continue to be used or sold without land remediation. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems.

Stock Compensation Plans

At September 30, 2003, SPR had several stock-based compensation plans. SPR applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. SPR has adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock Based Compensation, and its related amendment(s).

Unbilled Receivables

Revenues related to the sale of energy are recorded based on metered usage. Meters are read on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities’ current tariffs. Customer accounts receivable as of September 30, 2003, include unbilled receivables of $92.2 million and $49 million for NPC and SPPC, respectively. Customer accounts receivable as of September 30, 2002, include unbilled receivables of $77.5 million and $50.4 million for NPC and SPPC, respectively.

Provision for Uncollectible Accounts

The Utilities reserve for doubtful accounts based on past experience writing off uncollectible customer accounts. The adequacy of these reserves will vary to the extent that future collections differ from past experience.

FINANCIAL CONDITION AND MATERIAL CHANGES IN RESULTS OF OPERATIONS

Sierra Pacific Resources

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later.

During the three months ended September 30, 2003, SPR recognized net income of $87.8 million compared to net income of $80.3 million for the same period during 2002. Operating results for the three months ended September 30, 2003, were significantly affected by the following items (before income taxes):

• an unrealized gain of $61.5 million on the derivative instrument associated with the issuance of $300 million of convertible debt (see Critical Accounting Policies). This unrealized gain has no effect on cash flows;

• other operating expenses that included increased reserves for uncollectible accounts and costs associated with collections for NPC and SPPC (see Other Income/(Expense analysis);

• interest costs at SPR, NPC, and SPPC that included the recognition of $40.2 million in interest as a result of a judgment issued September 26, 2003, by the Enron Bankruptcy Court. See Note 11, Commitments and Contingencies, of the Consolidated Financial Statements for more information regarding the Enron litigation.

During the first nine months of 2003, SPR incurred a net loss of $100.1 million compared to a $265.1 million net loss for the same period during 2002. Similar to the items affecting the three month operating results, SPR operating results for the nine months ended September 30, 2003, were negatively affected by the following significant items (before income taxes):

• an unrealized loss of $46.1 million on the derivative instrument associated with the issuance of $300 million of convertible debt. This unrealized loss has no effect on cash flows;

• the write-off of disallowed deferred energy costs (excluding carrying charges) of approximately $46 million and $45 million by NPC and SPPC, respectively;

• losses by SPR subsidiaries due to the recognition of asset impairments and business disposals of $32.9 million and $9.6 million by SPC and e ·three, respectively;

• other operating expenses that included increased reserves for uncollectible accounts and costs associated with collections for NPC and SPPC (see Other Income/(Expense analysis); and

• interest costs at SPR, NPC, and SPPC, including $40.2 million as a result of the Enron Bankruptcy Court judgment.

SPR operating results for the same nine month period during 2002 were negatively affected by write-offs of $434.1 million and $53.1 million of disallowed deferred energy costs by NPC and SPPC, respectively.

SPR did not pay or declare a common dividend in the first nine months of 2003, nor did NPC and SPPC declare or pay common stock dividends to their parent, SPR, during the same period. SPPC paid $2.925 million in dividends to holders of its preferred stock during the first nine months of 2003.

Liquidity and Capital Resources (SPR Consolidated)

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 may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. 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 restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below.

• NPC’s first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC’s common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $220 million as of September 30, 2003), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. Management is currently in the process of seeking consent for the modification of this restriction. There can be no assurance that any such consent can be obtained or that any non-consenting first mortgage bonds could be redeemed or defeased prior to their stated maturity. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock, although other restrictions set forth below would limit the amount of any such repurchases or redemptions.

• NPC’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, and NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued on August 13, 2003, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s Premium Income Equity Securities (PIES)) provided that:

• those payments do not exceed $60 million for any one calendar year,

• those payments comply with any regulatory restrictions then applicable to NPC, and

• the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1.

• the sum of 50% of NPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the applicable series of Notes, plus

• 100% of NPC’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 NPC, plus

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

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

• On October 29, 2002, NPC established an accounts receivables purchase facility, which was renewed on October 28, 2003, and will expire on October 26, 2004. The agreements relating to the receivables purchase facility contain various covenants, including a limitation on payments in respect of common stock by NPC to SPR that is identical to the limitation contained in NPC’s General and Refunding Mortgage Notes, Series E & Series G, described above.

• The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC’s request for authority to issue Long-Term Debt. The PUCN order requires that, until such time as the order’s authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any

dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of September 30, 2003, NPC’s equity ratio was 36.66%. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction.

• The terms of NPC’s preferred trust securities provide that no dividends may be paid on NPC’s common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures.

• SPPC’s Term Loan Agreement dated October 30, 2002, as amended, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $90 million, $80 million, and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004, and 2005, respectively. The Term Loan Agreement also permits SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of:

• 50% of SPPC’s Consolidated Net Income for the period commencing January 1, 2003, and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus

• the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period.

• On October 29, 2002, SPPC established an accounts receivables purchase facility, which was renewed on October 28, 2003, and expires on October 26, 2004. The agreements relating to the receivables purchase facility contain various covenants, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC’s Term Loan Agreement, described above.

• SPPC’s Articles of Incorporation contain restrictions on the payment of dividends on SPPC’s common stock in the event of a default in the payment of dividends on SPPC’s preferred stock. SPPC’s Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption, or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock.

• The Utilities are subject to the provision of the Federal Power Act that states that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction would not be construed or applied to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts.

• On November 6, 2003, the Bankruptcy Court issued an order staying execution pending appeal of the September 26, 2003 judgment entered in favor of Enron against the Utilities. One of the conditions of the stay order is that the Utilities cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations. The Utilities have the right to seek modification of the conditions of the stay if there is a material change in the facts upon which the stay order is based.

Effects of 2002 Rate Case Decisions

On March 29 and April 1, 2002, S&P and Moody’s lowered the unsecured debt ratings of SPR, NPC, and SPPC to below investment grade in response to the decision of the PUCN with respect to NPC’s rate cases. On April 23 and 24, 2002, the unsecured debt ratings of SPR and the Utilities were further downgraded by both rating agencies, and the Utilities’ secured debt ratings were downgraded to below investment grade. The downgrades affected SPR’s, NPC’s, and SPPC’s liquidity primarily in two principal areas: (1) their respective financing arrangements, and (2) NPC’s and SPPC’s contracts for fuel, for purchase and sale of electricity, and for transportation of natural gas.

For more detailed discussion of these effects, please see SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

Accounts Receivable Facilities

On October 29, 2002, NPC and SPPC established accounts receivable purchase facilities of up to $125 million and $75 million, respectively. Both facilities were renewed on October 28, 2003, and will expire on October 26, 2004. If NPC and/or SPPC elect to activate their receivables purchase facilities, they will sell all of their accounts receivable generated from the sale of electricity and natural gas to customers to their newly created bankruptcy-remote special purpose subsidiaries. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiaries will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased receivables.

The agreements relating to the receivables purchase facilities contain various conditions to purchase covenants, and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, each Utilities’ receivables purchase facility may terminate in the event that the Utility or SPR defaults (i) on the payment of indebtedness, or (ii) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for the Utility and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, each Utility’s facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of the Utility. SPR has agreed to guaranty the performance by NPC and SPPC of certain obligations as sellers and servicers under the receivables purchase facilities. NPC and SPPC intend to use their accounts receivables purchase facilities as back-up liquidity facilities and do not plan to activate these facilities in the foreseeable future.

Cross Default Provisions

Certain financing agreements of SPR and the Utilities contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPR and the Utilities 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 briefly summarized below:

• The indenture pursuant to which SPR issued its 7.25% Convertible Notes due 2010 provides for an event of default if SPR or any of its significant subsidiaries (NPC and SPPC) fails to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable;

• NPC’s General and Refunding Mortgage Indenture, under which NPC has $1.08 billion of securities outstanding as of September 30, 2003, provides for an event of default if a matured event of default under NPC’s First Mortgage Indenture occurs;

• The terms of NPC’s Series E Notes and NPC’s Series G Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of each series of Notes to require NPC to redeem their series of Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding noteholders for such series of Notes;

• NPC’s receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively;

• NPC’s Senior Unsecured Note Indenture, pursuant to which NPC issued its $130 million 6.20% Senior Unsecured Notes, Series B, due April 15, 2004, provides for a default if (a) NPC fails to pay indebtedness (after any applicable grace period), or (b) any of NPC’s indebtedness is accelerated, and (c) such indebtedness aggregates $15 million, and (d) such indebtedness is not repaid and such acceleration is not rescinded within 30 days;

• SPPC’s General and Refunding Mortgage Indenture, under which SPPC has $499.3 million of securities outstanding as of September 30, 2003, provides for an event of default if a matured event of default under SPPC’s First Mortgage Indenture occurs;

• SPPC’s Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC’s General and Refunding Mortgage Indenture ceases to be enforceable; and

• SPPC’s receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively.

Judgment Related Defaults

Nevada Power Company

NPC’s First Mortgage Indenture provides for an event of default if a final, unstayed judgment in excess of $25,000 is rendered against NPC and remains undischarged for 60 days. Upon a matured event of default, the trustee may, and upon the written request of the holders of at least 25% of the bonds outstanding under NPC’s First Mortgage Indenture, is required to declare the principal of and interest on the approximately $372.5 million of outstanding First Mortgage bonds immediately due and payable.

NPC’s $250 million Series E and $350 million Series G General and Refunding Mortgage Notes and NPC’s $130 million 6.2% Senior Unsecured Notes, Series B, due April 15, 2004, provide for an event of default if a final, unstayed judgment in excess of $15 million is rendered against NPC and remains undischarged for 60 days. Since the Series E Notes and the Series G Notes were issued under NPC’s General and Refunding Mortgage Indenture and NPC’s Senior Unsecured Notes are secured by a General and Refunding Mortgage Bond, a default under any of the Series E Notes, the Series G Notes and the Senior Unsecured Notes, will trigger a default under NPC’s General and Refunding Mortgage Indenture. In addition, a matured event of default under NPC’s First Mortgage Indenture will trigger a default under NPC’s General and Refunding Mortgage Indenture. Upon a matured event of default under the NPC’s General and Refunding Mortgage Indenture, the trustee or the holders of 33% of the General and Refunding Mortgage securities outstanding may declare the principal and accrued interest of the approximately $1.08 billion of outstanding General and Refunding Mortgage securities immediately due and payable.

If a judgment lien is created on NPC’s real property located in Nevada, NPC has been advised that the judgment lien would be an interceding lien that would have priority over subsequent advances under NPC’s General and Refunding Mortgage Indenture; therefore, NPC would be unable to provide certain required opinions of counsel to issue additional securities under its General and Refunding Mortgage Indenture until the judgment lien is discharged and released. Since NPC is unable to issue additional bonds under its First Mortgage Indenture, its sole means of issuing secured debt is through its General and Refunding Mortgage Indenture.

If NPC’s indebtedness under either its First Mortgage Indenture and/or its General and Refunding Mortgage Indenture is accelerated, or if NPC is unable to issue additional securities under its General and Refunding Mortgage Indenture in order to raise funds for operations and to repay indebtedness and to provide security, as needed, for its obligations, NPC would likely be unable to continue to operate outside of bankruptcy.

Sierra Pacific Power Company

SPPC’s $100 million Term Loan Agreement provides for an event of default if a judgment of $10 million or more is entered against SPPC and such judgment is not vacated, discharged, stayed or bonded pending appeal within 30 days. The Term Loan Agreement also prohibits the creation or existence of any liens on SPPC’s properties except for liens specifically permitted under the Term Loan Agreement. If a judgment lien is filed against SPPC, the filing of the lien will trigger an event of default under the Term Loan Agreement. Upon an event of default, the Administrative Agent under the Term Loan Agreement may, upon request of more than 50% of the lenders under the Term Loan Agreement, declare all amounts due under the Term Loan Agreement immediately due and payable. Currently, SPPC has $99.3 million outstanding under its Term Loan facility.

SPPC’s obligations under the Term Loan Agreement are secured by a General and Refunding Mortgage Bond. If SPPC fails to repay all amounts due upon an acceleration under the Term Loan Agreement within 3 business days, such failure will be deemed a default in the payment of principal and will trigger an event of default under the SPPC General and Refunding Mortgage Indenture that would be applicable to all securities issued under the SPPC General and Refunding Mortgage Indenture.

In the event that SPPC’s Term Loan is accelerated and results in the acceleration of all amounts outstanding under SPPC’s General and Refunding Mortgage Indenture, SPPC would likely be unable to continue to operate outside of bankruptcy.

If a judgment lien is created on SPPC’s real property located in Nevada, SPPC has been advised that the judgment lien would be an interceding lien that would have priority over subsequent advances under SPPC’s General and Refunding Mortgage Indenture; therefore, SPPC would be unable to provide certain required opinions of counsel to issue additional securities under its General and Refunding Mortgage Indenture until the judgment lien is discharged and released. Since SPPC is unable to issue additional bonds under its First Mortgage Indenture, its sole means of issuing secured debt is through its General and Refunding Mortgage Indenture. If SPPC is unable to issue additional securities under its General and Refunding Mortgage Indenture in order to raise funds for operations and to repay indebtedness and to provide security, as needed, for its obligations, SPPC would likely be unable to continue to operate outside of bankruptcy.

Financing Transactions

On February 5, 2003, SPR issued approximately 13.66 million shares of common stock in exchange for a total of 2.1 million of its PIES in five privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933.

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes were used to repurchase approximately $58.5 million of SPR’s Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million were used to repay SPR’s Floating Rate Notes due April 20, 2003, and the remaining proceeds were available for general corporate purposes. The Convertible Notes were issued with registration rights.

On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. Before SPR received shareholder approval, holders of the Convertible Notes were entitled to receive both shares of common stock and cash upon conversion on their notes. As a result of receiving shareholder approval, through the close of business on February 14, 2010, for each $1,000 principal amount of the Convertible Notes surrendered, SPR has the option to issue (i) 76.7073 shares of Common Stock plus an amount of cash equal to the then market value of 142.4564 shares of our Common Stock, subject to adjustment upon the occurrence of certain dilution events; or (ii) 219.1637 shares of our Common Stock, subject to adjustment upon the occurrence of certain dilution events. If the noteholders present the Convertible Notes for conversion and SPR elects to convert the notes into stock and cash, the total amount of the cash payable on conversion would be approximately $253.6 million, at an assumed five-day average closing price of $5.93 per share (based upon the last reported sale price of SPR’s common stock on November 3, 2003). The amount of cash payable on conversion of the Convertible Notes will increase as the average closing price of SPR’s common stock increases. For further information regarding the terms of the Convertible Notes, see Note 4, Long-Term Debt.

Effect of Holding Company Structure

Currently, SPR (on a stand-alone basis) has a substantial amount of outstanding debt and other obligations including, but not limited to: $300 million of its unsecured 8¾% Senior Notes due 2005; $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010.

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 its subsidiaries’ creditors, particularly those of NPC and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders, NPC’s preferred trust security holders, and SPPC’s preferred stockholders. As of September 30, 2003, NPC, SPPC, and their subsidiaries had approximately $3.04 billion of debt and other obligations outstanding including $188.9 million previously reported as preferred trust securities of NPC, but which has been reclassified to Long-Term Debt in accordance with SFAS 150. See Note 4, Long-Term Debt, for further discussion. Additionally, SPPC had $50.0 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

During the three and nine months ended September 30, 2003, NPC recognized net income of approximately $62.5 million and $25.1 million, respectively, and did not pay or declare a common stock dividend to its parent, SPR. Operating results during the nine month period was negatively affected by the write-off of $46 million in May 2003 of disallowed deferred energy costs, and the recognition of $27.8 million of interest costs as a result of a September 26, 2003,

judgment by the Enron Bankruptcy Court Judge, both described later. The causes for significant changes in specific lines comprising the results of operations for NPC are as follows:

Electric Operating Revenues


			Three Months							Nine Months
			Ended September 30,							Ended September 30,

							Change from							Change from
			2003		2002		Prior Year %			2003		2002		Prior Year %

Electric Operating Revenues ($000)
	Residential		$	266,585	$	266,508		0.0	%	$	555,514	$	564,439		-1.6	%
	Commercial			103,638		103,367		0.3	%		264,861		263,425		0.5	%
	Industrial			193,601		189,440		2.2	%		414,177		413,602		0.1	%

	Retail revenues			563,824		559,315		0.8	%		1,234,552		1,241,466		-0.6	%
	Other			75,837		153,221		-50.5	%		162,273		304,401		-46.7	%

		Total Revenues	$	639,661	$	712,536		-10.2	%	$	1,396,825	$	1,545,867		-9.6	%

	Retail sales in thousands of megawatt-hours (MWH)			6,166		5,814		6.1	%		14,053		13,699		2.6	%
	Average retail revenue per MWH		$	91.44	$	96.20		-4.9	%	$	87.85	$	90.62		-3.1	%

Retail revenues were slightly higher for the three months ended September 30, 2003, compared to the same period in 2002, due to warmer than normal weather and customer growth. Partially offsetting this increase was a decrease in retail rates that was effective May 19, 2003, as a result of NPC’s Deferred Energy Case (see Regulatory Matters, later).

For the nine months ended September 30, 2003, retail revenues were slightly lower than the same period in 2002 primarily due to lower average retail rates in 2003 as a result of the aforementioned rate decrease effective May 19, 2003. This decrease in revenues was partially offset by an increase in revenues related to increases in residential, commercial, and industrial customers (5.1%, 5.0%, and 5.9%, respectively). Higher revenues in 2002 resulting from one-time rate increase in June 2002 of $.01 per kilowatt-hour, which allowed NPC to accelerate the recovery of its deferred energy balance, also contributed to the 2003 decrease in revenues.

Other electric operating revenues decreased for the three and nine months ended September 30, 2003, compared to the same periods in 2002, due to a decrease in the sales volumes of wholesale electric power to other utilities. See NPC’s Annual Report in Form 10-K for the year ended December 31, 2002, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation - Energy Supply, for a discussion of NPC’s purchases power procurement strategies.

Purchased Power


	Three Months							Nine Months
	Ended September 30,							Ended September 30,

					Change from							Change from
	2003		2002		Prior Year %			2003		2002		Prior Year %

Purchased Power ($000)	$	301,683	$	440,559		-31.5	%	$	620,712	$	1,102,551		-43.7	%
Purchased Power in thousands of MWHs		4,084		5,330		-23.4	%		9,494		11,112		-14.6	%
Average cost per MWH of Purchased Power (1)	$	73.87	$	82.66		-10.6	%	$	65.38	$	78.61		-16.8	%

(1) Nine months ended September 30, 2002 average costs do not include contract termination costs discussed below

Purchased power costs were lower for the three months and nine months ended September 30, 2003, than the same period in the prior year primarily as a result of a decrease in the volumes purchased and a decrease in the price of Short-Term Firm energy. Additionally, lower costs resulted from a $229 million provision for terminated purchased power contracts that was recorded in the second quarter of 2002. See Part II, Item I - Legal Proceedings, in this report and SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, for a discussion of the terminated purchased power contracts. Finally, purchases associated with risk management activities, which are included in purchased power, decreased in 2003. Risk management activities include transactions entered into to minimize purchased power costs. See SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation - Energy Supply, for a discussion of NPC’s purchased power procurement.

Fuel For Power Generation


	Three Months							Nine Months
	Ended September 30,							Ended September 30,

					Change from							Change from
	2003		2002		Prior Year %			2003		2002		Prior Year %

Fuel for Power Generation ($000)	$	126,839	$	87,864		44.4	%	$	246,643	$	245,060		0.6	%
Thousands of MWHs generated		3,476		2,936		18.4	%		7,513		7,592		-1.0	%
Average cost per MWH of Generated Power	$	36.49	$	29.93		21.9	%	$	32.83	$	32.28		1.7	%

Fuel for power generation costs for the three months ended September 30, 2003, were higher than the same period in 2002 due to the increase in the volume of coal generation and higher gas prices. The increase in generation volume was as a result of an increase in retail sales. Fuel for generation costs for the nine months ended September 30, 2003, were comparable to the same period in 2002 with slightly higher costs being offset by lower volumes.

Deferred Energy Costs


	Three Months									Nine Months
	Ended September 30,									Ended September 30,

							Change from								Change from
	2003			2002			Prior Year %			2003		2002			Prior Year %

Deferred energy costs disallowed ($000)		—				—		N/A			45,964		434,123			-89.4	%
Deferred energy costs - net ($000)	$	(35,967	)	$	(43,224	)		-16.8	%	$	48,260	$	(238,059	)		N/A

Deferred energy costs disallowed for the nine months ended September 30, 2003, reflects the PUCN disallowance of approximately $46 million in May 2003, of deferred energy costs incurred during the twelve months ended September 30, 2002. Deferred energy costs disallowed for the nine months ended September 30, 2002, reflects the write-off of approximately $434 million of deferred energy costs incurred during the seven months ended September 30, 2001, that were disallowed by the PUCN in NPC’s 2001 deferred energy rate case.

Deferred energy costs - net increased for the three month period ended September 30, 2003, compared to the same period during 2002, primarily as a result of an increase in the amortization of prior deferred energy costs. Also, the 2003 increase reflects a decrease in the amount that fuel and purchase power costs incurred during 2003 exceeded the recovery of those costs through rates. During periods when fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as reduction in costs and as a receivable to be collected through future rate adjustments. The reduction in costs during the three months ended September 30, 2003, was less than the amount recognized during the same period during 2002.

Deferred energy costs - net increased for the nine month period ended September 30, 2003, compared to the same period during 2002, primarily as a result of the deferral in the second quarter of 2002 of approximately $229 million for contract termination costs. Additionally, 2003 costs increased as a result of greater amortization of prior deferred energy costs compared to 2002. Finally, deferred energy costs were also higher during 2003 because of a decrease in the amount that fuel and purchase power costs exceeded the recovery of those costs through rates.

Allowance For Funds Used During Construction (AFUDC)


	Three Months								Nine Months
	Ended September 30,								Ended September 30,

						Change							Change
						from Prior							from Prior
	2003		2002			Year %			2003		2002		Year %

Allowance for other funds used during construction ($000)	$	281	$	(262	)		N/A		$	1,922	$	239		704.2	%
Allowance for borrowed funds used during construction ($000)	$	573	$	208			175.5	%	$	2,149	$	2,169		-0.9	%

	$	854	$	(54	)		N/A		$	4,071	$	2,408		69.1	%

NPC’s total allowance for funds used during construction was higher for the three month and nine month periods ended September 30, 2003, than the comparable periods in 2002, as a result of an increase in the AFUDC debt and equity rates.

Other (Income) and Expenses


	Three Months									Nine Months
	Ended September 30,									Ended September 30,

							Change									Change
							from Prior									from Prior
($000)	2003			2002			Year %			2003			2002			Year %

Other operating expense	$	44,749		$	39,250			14.0	%	$	136,964		$	116,520			17.5	%
Maintenance expense	$	9,203		$	8,050			14.3	%	$	38,390		$	31,576			21.6	%
Depreciation and amortization	$	28,474		$	24,975			14.0	%	$	81,095		$	72,924			11.2	%
Income taxes	$	30,556		$	39,944			-23.5	%	$	3,734		$	(116,536	)		N/A
Taxes other than income taxes	$	6,387		$	5,935			7.6	%	$	19,429		$	19,122			1.6	%
Interest charges on long-term debt	$	37,600		$	23,714			58.6	%	$	104,215		$	70,668			47.5	%
Interest charges-other	$	34,171		$	7,251			371.3	%	$	46,165		$	14,133			226.6	%
Interest accrued on deferred energy	$	(5,952	)	$	(8,506	)		-30.0	%	$	(16,896	)	$	(5,411	)		212.3	%
Other income	$	(4,277	)	$	(2,451	)		74.5	%	$	(11,633	)	$	(3,792	)		206.8	%
Other expense	$	1,441		$	3,184			-54.7	%	$	4,491		$	9,745			-53.9	%
Income taxes - other income and expense	$	3,084		$	2,840			8.6	%	$	8,277		$	297			2686.9	%

Other operating expense for the three month period ending September 30, 2003, was greater than the same period during the prior year, due primarily to increased reserves for uncollectible accounts, costs associated with increased billing and collection efforts, and higher employee labor overhead costs along with higher operating costs at the Navajo and Mohave generating facilities. Expenses for the nine month period were greater due to the aforementioned expenses along with increased insurance premiums and the recognition of short-term incentive compensation plan costs in 2003. NPC did not recognize incentive plan costs during the same period in 2002.

Maintenance costs for the three and nine month periods ending September 30, 2003, were higher than the same periods in 2002 due to higher plant maintenance costs during 2003.

Depreciation and amortization was higher for the three month period ended September 30, 2003, compared to the same period in 2002 as a result of both an adjustment that reduced depreciation in May 2002 and depreciation on software placed in service in 2003. Depreciation and amortization was higher for the nine month period ended September 30, 2003, compared to the same period in 2002 as a result of an increase in depreciable assets, including the Centennial Project, and the addition of new software in 2003.

NPC’s income taxes decreased for the three months ended September 30, 2003, compared to the amount recognized during the same period in 2002. The change resulted from changes in pretax income. The decrease in pretax income resulted from increases in other operating, maintenance, depreciation and amortization, and interest expenses and a decrease in revenues, partially offset by a decrease in fuel and purchase power expense.

NPC’s income taxes increased for the nine months ended September 30, 2003, compared to the same period in 2002 due to pretax income in 2003 compared to pretax losses in 2002. The change in pretax income resulted largely from the write-off in 2002 of disallowed deferred energy costs that was partially offset by a decrease in revenues and increases in other operating, maintenance, depreciation, and interest expenses during 2003.

Taxes other than income taxes for the three and nine months ended September 30, 2003, were comparable to amounts recognized during the same periods in 2002.

Interest charges on Long-Term Debt for the three and nine month periods ended September 30, 2003, increased as the result of the adoption of SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” requiring the reclassification of NPC’s Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities to interest charges on Long-Term Debt. For the three and nine month periods ended September 30, 2003, $3.8 million, and $11.4 million of dividends, respectively, were reclassified to interest charges on Long-Term Debt. (See Note 1, Recent Pronouncements, for discussion of SFAS No. 150). For the comparable periods in, 2002, the income statement presentation remains as originally presented. Aside from the impact of the reclassifications, interest charges on Long-Term Debt for the three and nine month periods ending September 30, 2003, increased over the same periods in 2002 due primarily to the issuance in October 2002 of $250 million additional debt at an interest rate of 10.875% and the issuance, in August 2003 of $350 million General and Refunding Bonds at an interest rate of 9.00%. The redemptions, in September 2003 and October 2002, of $350 million and $15 million of debt, respectively, slightly offset the increase in interest during 2003 over 2002.

Interest charges-other for the three months ended September 30, 2003, increased, compared to the prior year period, due to higher interest on delayed/terminated contracts. NPC recorded in September 2003 $27.8 million of additional interest costs on terminated contracts as a result of a final judgment issued on September 26, 2003, by the Bankruptcy Court Judge overseeing the bankruptcy case of Enron Power Marketing (Enron). See Note 11, Commitments and Contingencies, of the Consolidated Financial Statements for more information regarding the Enron litigation. Higher charges related to debt discount and expenses associated with the October 2002 $250 million Notes issuance and the August 2003 $350 million Notes issuance. For the nine month period ending September 30, 2003, other interest charges were higher, compared to the same period in 2002 due to the aforementioned $27.8 million of additional interest costs on terminated contracts, greater year-to-date interest on delayed/terminated contracts, charges related to fees associated with NPC’s credit facilities and receivables conduit, and to the amortization of increased debt discount charges related to the additional debt issuances.

Interest accrued on deferred energy costs decreased during the three months ended September 30, 2003, compared to the same period in 2002, following lower deferred fuel and purchased power balances during 2003. For the nine months ended September 30, 2003, the increase over the same period in 2002 compared favorably due to the first quarter 2002 write-off of approximately $20.1 million of carrying charges, net of taxes, on deferred energy costs that were disallowed by the PUCN in its March 29, 2002, decision on NPC’s deferred energy rate case. The 2002 write-off was partially offset by the recording of carrying charges on deferred energy costs incurred.

Other income for the three months ended September 30, 2003, increased over the same period in 2002 due, primarily, to the continued recording of gains from the disposition of non-essential property during 2003. Other income increased for the nine months ended September 30, 2003, compared to the same period in 2002, due to the recognition of income from the disposition of SO2 allowances in 2003, an increase in gains from the disposition of non-utility property in 2003, income generated as a result of the relocation of electricity lines for Clark County, and the recognition of carrying charges related to divestiture costs ordered by the PUCN, and an increase in interest income.

Other expense decreased during the three months ended September 30, 2003, compared to the same period in 2002 as a result of decreased expenditures related to low-income energy assistance programs, lobbying and ballot initiative charges, and charges related to depreciation on non-utility property. Other expense decreased during the nine months ended September 30, 2003, compared to the same period in 2002 due, primarily, to the 2002 write-off of $5.0 million relating to the disposition of SO2 allowances as ordered by the PUCN.

NPC’s income taxes - other income and expenses for the three months ended September 30, 2003, were comparable to amounts recognized during the same period in 2002.

NPC’s income taxes - other income and expenses increased for the nine months ended September 30, 2003, compared to amounts recognized the same period during 2002 due to an increase in pretax income largely as a result of a write-off of disallowed interest charges on deferred energy costs in 2002.

Analysis of Cash Flows

NPC’s cash flows were less during the nine-months ended September 30, 2003, compared to the same period in 2002, resulting primarily from decreases in cash flows from operating and financing activities. The decrease in cash from operating activities was substantially as a result of the prepayment of fuel and power purchases during 2003 and the receipt of an income tax refund in 2002 both, partially offset, by the collection in 2003 of previously deferred energy costs as a result of a rate increase that began April 1, 2002. The decrease operating cash flow was partially offset by the collection of previously deferred energy costs due to the PUCN decision in NPC’s 2001 deferred energy rate case, that resulted in increased rates beginning April 1, 2002. Cash flows from financing activities were lower in 2003 because of cash provided by short-term borrowings during 2002. NPC also utilized additional cash for financing activities in 2003 for the Centennial Plan and other construction projects.

Liquidity and Capital Resources

NPC had cash and cash equivalents of approximately $97.2 million at September 30, 2003.

Due to NPC’s weakened financial condition and, in certain instances, the weakened financial condition of NPC’s power suppliers, NPC has been required to pre-pay its power purchases or make more frequent payments on its power deliveries. As a result of unseasonably cool weather during the spring of 2003 and its prepayment and more frequent payment obligations for its summer 2003 power requirements, NPC’s liquidity was significantly constrained during the early summer months of 2003. If NPC does not have sufficient liquidity to meet its power requirements, particularly at the onset of future summer seasons, NPC may be required to issue or incur additional indebtedness. If NPC is unable to issue or incur such indebtedness, whether due to lack of access to the capital markets, lack of regulatory authority to issue or incur such debt, or restrictive covenants in certain of its financing agreements (see below), its ability to provide power and its financial condition will be adversely affected.

NPC’s liquidity would be significantly affected by a requirement to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron, a requirement to provide cash collateral in excess of the $24 million NPC is required to deposit into escrow within 90 days from the order date, for Enron’s claims for termination payments under the judgment, or unfavorable rulings by the PUCN in future NPC rate cases (including terminated power supply contracts). In response to the announcement of the decision of the Bankruptcy Court on August 28, 2003, in favor of Enron, S&P and Moody’s placed NPC on “credit watch with negative implications” and “negative rating outlook,” respectively. Future downgrades by either S&P or Moody’s could preclude or reduce NPC’s access to the capital markets, and could adversely affect NPC’s ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing and regulatory contingencies, as discussed in Note 11, Commitments and Contingencies, could have a material adverse effect on NPC’s financial condition and liquidity, and could make it difficult for NPC to continue to operate outside of bankruptcy.

Effect of 2002 Rate Case Decisions

On March 29 and April 1, 2002, following the decision by the PUCN in NPC’s deferred energy rate case, S&P and Moody’s lowered NPC’s unsecured debt ratings to below investment grade. On April 23 and 24, 2002, NPC’s unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. As a result of these downgrades, NPC’s ability to access the capital markets to raise funds was severely limited. Since SPR’s credit ratings were similarly downgraded, SPR’s ability to make capital contributions to NPC also became severely limited.

For more detailed discussion of these effects, please see SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

Financing Transactions

The Series G Notes limit the amount of payments that NPC may pay on its common stock to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited

to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series G Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $25 million from the date of the issuance of the Series G Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series G Notes, NPC can meet a fixed charge coverage ratio test, and the total amount of such dividends is less than (i) the sum of 50% of NPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series G Notes, plus (ii) 100% of NPC’s aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC’s investment in certain subsidiaries.

The terms of the Series G Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, 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, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Resource Plan, and certain letters of credit issued to support NPC’s obligations with respect to energy suppliers.

Credit Facility

On June 30, 2003, NPC entered into a $60 million revolving Credit Agreement to provide additional liquidity to NPC for its summer 2003 power purchases. This facility was paid off on August 11, 2003, and was terminated on August 18, 2003.

Accounts Receivable Facility

On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million. The receivables purchase facility was renewed on October 28, 2003, and expires as of October 26, 2004. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased receivables.

The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, NPC’s facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of NPC. In addition, the agreements contain a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC’s General and Refunding Mortgage Notes, Series E, described below. SPR has agreed to guaranty NPC’s performance of certain obligations as a seller and servicer under the receivables purchase facility.

NPC has agreed to issue a $125 million General and Refunding Mortgage Bond upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of NPC’s obligations as seller and servicer, plus certain interest, fees, and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond.

NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future.

Mortgage Indentures

NPC’s first mortgage indenture creates a first priority lien on substantially all of NPC’s properties. As of September 30, 2003, $372.5 million of NPC’s first mortgage bonds were outstanding. NPC agreed in connection with its Series E Notes and its Series G Notes that it would not issue any more first mortgage bonds.

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 September 30, 2003, $1.08 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 (i) 70% of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage Bonds, and/or (iii) the principal amount of first mortgage bonds retired after October 19, 2001. On the basis of (i), (ii) and (iii) above, as of September 30, 2003, NPC had the capacity to issue approximately $911.5 million of additional General and Refunding Mortgage securities not including $235 million of General and Refunding bonds that will be issued into escrow during November 2003 in connection with the Enron litigation. See Note 11 of the Condensed Notes to Consolidated Financial Statements for more information regarding the Enron litigation. 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 Notes, the Series G Notes and the Receivables Purchase Facility Agreements limit the amount of additional indebtedness that NPC may issue and the reasons for which such indebtedness may be issued. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC’s receivables facility.

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 bonds issuable under that indenture.

Cross Default Provisions

Certain financing agreements of NPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of NPC and SPR 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 or SPR 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 briefly summarized below:

• NPC’s General and Refunding Mortgage Indenture, under which NPC has $1.08 billion of securities outstanding as of September 30, 2003, provides for an event of default if a matured event of default under NPC’s First Mortgage Indenture occurs;

• The terms of NPC’s Series E Notes and NPC’s Series G Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of each series of Notes to require NPC to redeem their Series of Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding noteholders for such series of Notes;

• NPC’s receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively; and

• NPC’s Senior Unsecured Note Indenture, pursuant to which NPC issued its $130 million 6.20% Senior Unsecured Notes, Series B, due April 15, 2004, provides for a default if (a) NPC fails to pay indebtedness (after any applicable grace period), or (b) any of NPC’s indebtedness is accelerated, and (x) such indebtedness aggregates $15 million, and (y) such indebtedness is not repaid and such acceleration is not rescinded within 30 days.

Judgment Related Defaults

Limitations on Indebtedness

The terms of NPC’s Series E Notes, which mature in 2009, and NPC’s Series G Notes, which mature in 2013, restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred

is specifically permitted, which includes limited amounts of debt with respect to 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 NPC’s obligations with respect to energy suppliers, and for the Series G Notes, indebtedness to finance capital expenditures incurred pursuant to NPC’s 2003 Resource Plan. At September 30, 2003, NPC met the fixed charge ratio test set forth in (i) above. If NPC’s Series E Notes and the Series G 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.

If NPC is unable to access the capital markets to issue additional indebtedness to support its operations, including the purchase of fuel and power, and to refinance its existing indebtedness, whether due to lack of access to the capital markets, lack of regulatory authority, or restrictive covenants in its financing agreements, its ability to provide power and its financial condition will be adversely affected. In addition, the PUCN conducted hearings on NPC’s Resource Plan on October 16, 2003. The PUCN approved an order on NPC’s Resource Plan on November 12, 2003. In general, the order approved NPC’s various requests made in its filing and also imposed additional requirements for various briefings, and required amendments to the plan if there are delays in the combined cycle units construction, issues with transmission reservations, or difficulties financing the plan. As such, NPC may need to expend up to approximately $500 million prior to the summer of 2007 for the construction and/or acquisition of generation facilities.

Sierra Pacific Power Company

During the three months ended September 30, 2003, SPPC recognized a net loss of $317 thousand and during the nine months ended September 30, 2003, SPPC recognized a net loss of $24.3 million. Operating results during both periods were negatively affected by a write-off of $45 million in June 2003 of disallowed deferred energy costs, and the recognition of $12.4 million of interest costs as a result of a September 26, 2003, judgment by the Enron Bankruptcy Court Judge (both described later). During the same period, SPPC paid $2.925 million in dividends to holders of its preferred stock, but did not declare nor pay dividends on its common stock, all of which is held by its parent, SPR.

The components of SPPC’s gross margin are set forth below (dollars in thousands):


			Three Months							Nine Months
			Ended September 30,							Ended September 30,

							Change from							Change from
			2003		2002		Prior Year %			2003		2002		Prior Year %

Operating Revenues:
	Electric		$	250,476	$	285,720		-12.3	%	$	660,956	$	707,558		-6.6	%
	Gas			13,931		18,473		-24.6	%		114,421		99,139		15.4	%

		Total Revenues	$	264,407	$	304,193		-13.1	%	$	775,377	$	806,697		-3.9	%

Energy Costs:
	Electric		$	165,575	$	198,727		-16.7	%	$	428,305	$	483,723		-11.5	%
	Gas			9,333		14,165		-34.1	%		91,335		76,234		19.8	%

		Total Energy Costs		174,908		212,892		-17.8	%		519,640		559,957		-7.2	%

Gross Margin by Segment:
	Electric		$	84,901	$	86,993		-2.4	%	$	232,651	$	223,835		3.9	%
	Gas			4,598		4,308		6.7	%		23,086		22,905		0.8	%

		Total	$	89,499	$	91,301		-2.0	%	$	255,737	$	246,740		3.6	%

The causes for significant changes in specific lines comprising the results of operations for SPPC are as follows:

Electric Operating Revenues


			Three Months							Nine Months
			Ended September 30,							Ended September 30,

							Change							Change
							from Prior							from Prior
			2003		2002		year %			2003		2002		year %

Electric Operating Revenues ($000)
	Residential		$	60,305	$	59,145		2.0	%	$	172,565	$	164,598		4.8	%
	Commercial			76,881		81,856		-6.1	%		208,746		203,211		2.7	%
	Industrial			75,752		76,776		-1.3	%		210,680		199,902		5.4	%

	Retail revenues			212,938		217,777		-2.2	%		591,991		567,711		4.3	%
	Other			37,538		67,943		-44.8	%		68,965		139,847		-50.7	%

		Total Revenues	$	250,476	$	285,720		-12.3	%	$	660,956	$	707,558		-6.6	%

	Retail sales in thousands of MWH			2,374		2,327		2.0	%		6,674		6,607		1.0	%
	Average retail revenue per MWH		$	89.70	$	93.59		-4.2	%	$	88.70	$	85.93		3.2	%

SPPC’s retail electric revenues for the three months ended September 30, 2003, were lower due to a rate decrease effective June 1, 2003, which was the result of SPPC’s 2003 deferred energy case (see Regulatory Matters, below).

The retail electric revenues for the nine months ended September 30, 2003, were higher than the same period in the prior year. This increase was primarily due to a rate increase effective June 1, 2002. Partially offsetting this increase was a decrease in the retail rates effective June 1, 2003, as a result of SPPC’s 2003 deferred energy case.

Other electric operating revenues decreased for the three and nine month periods ended September 30, 2003, compared to the same periods in 2002 due to a decrease in wholesale sales to other utilities. See SPPC’s Annual Report on Form 10-K for the year ended December 31, 2002, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, Energy Supply, for a discussion of SPPC’s purchased power procurement strategies.

Gas Operating Revenues


			Three Months							Nine Months
			Ended September 30,							Ended September 30,

							Change							Change
							from Prior							from Prior
			2003		2002		year %			2003		2002		year %

Gas Operating Revenues ($000)
	Residential		$	6,825	$	6,627		3.0	%	$	49,730	$	49,735		0.0	%
	Commercial			3,811		4,027		-5.4	%		25,536		26,112		-2.2	%
	Industrial			1,967		3,436		-42.8	%		9,999		14,996		-33.3	%

	Retail revenue			12,603		14,090		-10.6	%		85,265		90,843		-6.1	%
	Wholesale revenue			682		4,164		-83.6	%		27,275		6,669		309.0	%
	Miscellaneous			646		219		195.0	%		1,881		1,627		15.6	%

		Total Revenues	$	13,931	$	18,473		-24.6	%	$	114,421	$	99,139		15.4	%

	Retail sales in thousands of decatherms			1,179		1,311		-10.1	%		8,740		9,550		-8.5	%
	Average retail revenues per decatherm		$	10.69	$	10.75		-0.6	%	$	9.76	$	9.51		2.6	%

Residential gas revenues for the three months ended September 30, 2003, were slightly higher than the same period in 2002. The higher revenues in 2003 resulted from increases in the number of customers and in higher use per customer that were both partially offset by the effect of a rate decrease from SPPC’s purchased gas adjustment case, that was effective December 26, 2002. Residential gas revenues for the nine months ended September 30, 2003, were comparable to the same period in 2002.

Commercial gas revenues for the three months and nine months ended September 30, 2003, were slightly lower than the same periods in 2002 due to the aforementioned rate decrease that was effective December 26, 2002.

Industrial revenues for both the three and nine months ended September 30, 2003, were lower than the same periods in 2002 because some industrial customers switched to SPPC’s gas transportation tariff which gave those customers the ability to procure their gas from a source other than SPPC. The reduction in industrial revenues was also primarily responsible for the decrease in retail decatherm sales for the three and nine months ended September 30, 2003. Industrial revenues were also lower due to the rate decrease effective December 26, 2002, as mentioned above.

Wholesale gas revenues for the three months ending September 30, 2003, decreased from the same period in 2002 primarily due to a reduction in wholesale prices. Wholesale revenues for the nine months ended September 30, 2003, were higher than the same period in 2002 primarily due to the utilization of idle gas transportation capacity to move gas from Canada to California for resale.

Miscellaneous revenues increased for the three and nine months ended September 30, 2003, due to an increase in transportation revenue for the transport of the gas procured from other sources by the former Industrial customers.

Purchased Power


	Three Months							Nine Months
	Ended September 30,							Ended September 30,

					Change from							Change from
	2003		2002		Prior Year %			2003		2002		Prior Year %

Purchased Power ($000)	$	121,763	$	164,124		-25.8	%	$	284,615	$	443,843		-35.9	%
Purchased Power in thousands of MWHs		2,017		2,318		-13.0	%		5,230		5,642		-7.3	%
Average cost per MWH of Purchased Power (1)	$	60.37	$	70.80		-14.7	%	$	54.42	$	63.29		-14.0	%

(1) Nine months ended September 30, 2002 average cost does not include contract termination costs, discussed below

Purchased power costs were lower for the three months and nine months ended September 30, 2003, than the prior year primarily as a result of a decrease in the price and volume of SPPC’s risk management activities. Risk management activities include transactions entered into to minimize purchased power costs. See SPPC’s Annual Report on Form 10-K for the year ended December 31, 2002, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, Energy Supply, for a discussion of SPPC’s purchased power procurement strategies. In addition, the year-to-date figures were affected by the $86.8 million provision recorded in the second quarter of 2002 for terminated purchased power contracts. See Part II, Item I - Legal Proceedings, in this report and SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002 for a discussion of the terminated purchased power contracts.

Fuel For Power Generation


	Three Months							Nine Months
	Ended September 30,							Ended September 30,

					Change from							Change from
	2003		2002		Prior Year %			2003		2002		Prior Year %

Fuel for Power Generation ($000)	$	65,986	$	32,804		101.2	%	$	147,221	$	111,024		32.6	%
Thousands of MWHs generated		1,168		1,264		-7.6	%		3,068		3,605		-14.9	%
Average fuel cost per MWH of Generated Power	$	56.49	$	25.95		117.7	%	$	47.99	$	30.80		55.8	%

Fuel for power generation costs for the three and nine month periods ended September 30, 2003, were higher than the same periods in the prior year primarily because natural gas prices increased significantly. Partially offsetting this increase was a reduction in volume. The Valmy generating facility was not operating/shut down due to both scheduled and unscheduled maintenance in 2003.

Gas Purchased for Resale


	Three Months							Nine Months
	Ended September 30,							Ended September 30,

					Change from							Change from
	2003		2002		Prior Year %			2003		2002		Prior Year %

Gas Purchased for Resale ($000)	$	7,133	$	9,884		-27.8	%	$	77,332	$	61,585		25.6	%
Gas Purchased for Resale (thousands of decatherms)		1,587		2,882		-44.9	%		14,162		11,384		24.4	%
Average cost per decatherm	$	4.49	$	3.43		30.9	%	$	5.46	$	5.41		0.9	%

Gas purchased for resale decreased for the three month period ended September 30, 2003, as compared to the prior year period due to a decrease in wholesale activity, which more than offset an increase in gas prices experienced during the same period. Gas purchased for resale increased for the nine month period ended September 30, 2003, due to an increase in wholesale activity, as explained above.

Deferred Energy Costs


	Three Months								Nine Months
	Ended September 30,								Ended September 30,

						Change from									Change from
($000)	2003			2002		Prior Year %			2003			2002			Prior Year %

Deferred energy costs disallowed	$	—		$	—		N/A		$	45,000		$	53,101			-15.3	%
Deferred energy costs - electric - net	$	(22,174	)	$	1,799		-1332.6	%	$	(3,531	)	$	(71,144	)		-95.0	%
Deferred energy costs - gas - net	$	2,200		$	4,281		-48.6	%	$	14,023		$	14,649			-4.3	%

Deferred energy costs disallowed for the nine months ended September 30, 2003, reflects the June 1, 2003 disallowance, effective June 1, 2003, of $45 million pursuant to a stipulation approved by the PUCN. Deferred energy costs disallowed for the nine months ended September 30, 2002, reflects the write-off of $53 million of electric deferred energy costs incurred in the nine months ended November 30, 2001, that were disallowed by the PUCN in their May 28, 2002, decision.

The decrease in Deferred energy costs-electric-net for the three month period ended September 30, 2003, reflects an increase over 2002 in the amount that fuel and purchase power costs exceeded the recovery of those costs through rates. During periods when actual fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as a reduction in costs, as is the case above, and as a receivable to be collected through future rate adjustments. Additionally, deferred energy costs for the three month period ended September 30, 2003 were lower due to a reduction in the amortization of prior deferred energy costs compared to 2002.

The increase in Deferred energy costs-electric-net for the nine month period ended September 30, 2003, compared to the same period during 2002, resulted primarily from the deferral in the second quarter of 2002 of approximately $82 million for contract termination costs. Additionally, 2003 costs increased as a result of greater amortization of prior deferred energy costs compared to 2002. The 2003 increase in deferred energy costs was partially offset because of an increase over 2002 in the amount that fuel and purchase power costs exceeded the recovery of those costs through rates.

SPPC’s Deferred energy costs-gas-net decreased for the three and nine months ended September 30, 2003, primarily as a result of a decrease in the amount by which the recovery of natural gas costs through rates exceeded the cost of natural gas incurred

during 2003. The decrease in costs for both periods during 2003 was partially offset by an increase in the amortization of prior deferred gas costs, due to the PUCN authorized recovery of those costs.

Allowance For Funds Used During Construction (AFUDC)


	Three Months								Nine Months
	Ended September 30,								Ended September 30,

						Change							Change
						from Prior							from Prior
	2003		2002			Year %			2003		2002		Year %

Allowance for other funds used during construction ($000)	$	758	$	(10	)		N/A		$	1,961	$	143		1271.3	%
Allowance for borrowed funds used during construction ($000)		908		694			30.8	%		2,219		1,314		68.9	%

	$	1,666	$	684			143.6	%	$	4,180	$	1,457		186.9	%

Total allowance for funds used during construction increased for the three month and nine month periods ended September 30, 2003, compared to the same periods in the prior year due to increases in construction work in progress and an increase in the AFUDC Debt Rate.

Other (Income) and Expenses


	Three Months									Nine Months
	Ended September 30,									Ended September 30,

							Change from									Change from
($000)	2003			2002			Prior Year %			2003			2002			Prior Year %

Other operating expense	$	26,684		$	25,319			5.4	%	$	87,522		$	75,974			15.2	%
Maintenance expense	$	4,769		$	4,854			-1.8	%	$	16,409		$	15,250			7.6	%
Depreciation and amortization	$	20,811		$	19,034			9.3	%	$	60,478		$	57,186			5.8	%
Income taxes	$	(21	)	$	7,601			-100.3	%	$	(16,229	)	$	(9,037	)		79.6	%
Taxes other than income taxes	$	4,668		$	4,472			4.4	%	$	14,179		$	14,129			0.4	%
Interest charges on long-term debt	$	19,174		$	16,173			18.6	%	$	56,914		$	48,638			17.0	%
Interest charges-other	$	15,675		$	2,943			432.6	%	$	21,404		$	7,051			203.6	%
Interest accrued on deferred energy	$	(732	)	$	(2,207	)		-66.8	%	$	(4,246	)	$	(6,233	)		-31.9	%
Other income	$	(1,450	)	$	(1,880	)		-22.9	%	$	(3,500	)	$	(5,450	)		-35.8	%
Other expense	$	1,450		$	1,337			8.5	%	$	5,057		$	5,146			-1.7	%
Income taxes - other income and expense	$	454		$	796			-43.0	%	$	1,233		$	1,906			-35.3	%

Other operating expense for the three month period ending September 30, 2003, were greater than the prior year period due to the absence in 2003 of credits associated with the discontinuation of billing services for Truckee Meadows Water Authority (TMWA), costs associated with increased billing and collection efforts, and higher employee labor overhead costs. Other operating expenses for the nine month period ending September 30, 2003, were higher due to the aforementioned expenses along with increased insurance premiums, higher operating costs at the Tracy generation facility and the recognition of short-term incentive compensation plan costs in 2003. SPPC did not recognize incentive plan costs during the same period in 2002.

Maintenance expense for the three month period ending September 30, 2003, was comparable to the same period in 2002. However, Maintenance expense for the nine months ended September 30, 2003, was higher due to costs associated with outages at the Valmy generating facility.

Depreciation and amortization increased for the three month and nine month periods ended September 30, 2003, compared to the same period in 2002 as a result of an increase in depreciable assets due to growth.

SPPC’s income tax benefit for the three months ended September 30, 2003, resulted from pretax losses in 2003. The change resulted from changes in pretax income. The pretax losses resulted primarily from an increase in other operating expense, depreciation and amortization, and interest expense.

SPPC’s income tax benefit for the nine months ended September 30, 2003, increased compared to the amount recognized during the same period in 2002. The change resulted from an increase in pretax losses. The increase in pretax losses resulted primarily from increases in other operating, maintenance, depreciation and amortization, and interest expenses.

Taxes other than income taxes for the three and nine months ended September 30, 2003, were comparable to the amounts recognized during the same periods in 2002.

Interest charges on Long-Term Debt for the three and nine month periods ending September 30, 2003, increased over the comparable periods in 2002 due to the issuance in October 2002 of $100 million of additional debt at an interest rate of 10.5% and the renewal in May 2003 of $80 million of Washoe County Water Bonds at a higher interest rate.

Interest charges-other for the three months ended September 30, 2003, increased, compared to the same period in 2002. SPPC recorded in September 2003 $12.4 million of additional interest costs on terminated contracts as a result of a final judgment issued on September 26, 2003, by the Bankruptcy Court Judge overseeing the bankruptcy case of Enron Power Marketing (Enron). See Note 11, Commitments and Contingencies, of the Consolidated Financial Statements for more information regarding the Enron litigation. Additionally, interest charges-other increased due to higher debt discount and expenses related to the issuance in October 2002 of $100 million of additional debt, an increase in interest on delayed/terminated contracts, and the write-off of $.5 million of deferred interest related to SPPC’s Variable Rate Mechanism, as part of a stipulation reached with the PUCN in the Company’s Purchased Gas regulatory filing, and was reduced by the absence in 2003 of interest on short-term debt existing during the same period in 2002. During the nine month period ending September 30, 2003, Interest charges-other increased over the comparable period, in the prior year due, primarily, to the aforementioned $12.4 million of additional interest costs on terminated contracts, increased amortization of debt discount charges related to the October 2002 debt issuance and increased interest on delayed/terminated contracts. The absence of interest on short-term debt, compared to the same period, in the prior year, partially offset the increase from 2002.

Interest accrued on deferred energy costs decreased for the three month period ending September 30, 2003, compared to the same period in 2002 due to lower deferred fuel and purchased power balances during 2003. For the nine months ended September 30, 2003, compared to the same period in 2002 the decrease in these charges also followed lower deferred fuel and purchased power balances during 2003, offset partially by the write-off, during the comparable period in 2002, of approximately $2 million of carrying charges, net of taxes, that were disallowed by the PUCN in its May 28, 2002, decision on SPPC’s deferred energy rate case.

Other income for the three and nine months ended September 30, 2003, decreased compared to the same periods in the prior year due primarily to a decrease in interest income and subsidiary earnings, partially offset by increases in lease revenues and gains recognized from the sale of non-utility property.

Other expense for the three months and nine months ended September 30, 2003, were comparable to the amounts recognized during the same periods in 2002.

Income taxes - other income and expense for the three and nine months ended September 30, 2003, were comparable to the amounts recognized during the same periods in 2002.

Analysis of Cash Flows

SPPC’s cash flows were less during the nine-months ended September 30, 2003, compared to the same period in 2002, resulting primarily from decreases in cash flows from financing and investing activities, and minimally by a slight decrease in cash flows from operating activities. Cash flows from financing activities were lower primarily as a result of the cash provided in 2002 from short-term borrowings, offset partially by no common dividend payments to SPR during 2003. Cash flows from investing activities decreased in 2003 because of additional cash requirements for construction activity during 2003. Cash flows from operating activities decreased slightly due to a prepayment of fuel and energy purchases during 2003 and the receipt of an income tax refund in 2002. The decrease was partially offset by the decrease in wholesale sales to other utilities in 2003.

Liquidity and Capital Resources

SPPC had cash and cash equivalents of approximately $83.5 million at September 30, 2003.

Due to SPPC’s weakened financial condition and, in certain instances, the weakened financial condition of SPPC’s power suppliers, SPPC has been required to pre-pay its power purchases or make more frequent payments on its power deliveries. If SPPC does not have sufficient liquidity to meet its power requirements, SPPC may be required to issue additional indebtedness. If SPPC is unable to issue such indebtedness, whether due to lack of access to the capital markets, lack of regulatory authority to issue such debt, or restrictive covenants in its Term Loan Agreement (see below), its ability to provide power and its financial condition will be adversely affected.

SPPC’s liquidity would be significantly affected by a requirement to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron, a requirement to provide cash collateral in excess of the $11 million SPPC is required to deposit into escrow within 90 days from the order date for Enron’s claims for termination payments under the judgment, or unfavorable rulings by the PUCN in future SPPC rate cases (including terminated power supply contracts). In response to the announcement of the decision of the Bankruptcy Court on August 28, 2003, in favor of Enron, S&P and Moody’s placed SPPC on “credit watch with negative implications” and “negative rating outlook,” respectively. Future downgrades by either S&P or Moody’s could preclude or reduce SPPC’s access to the capital markets and could adversely affect SPPC’s ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing and regulatory contingencies, as discussed in Note 11, Commitments and Contingencies, could have a material adverse effect on SPPC’s financial condition and liquidity, and could make it difficult for SPPC to continue to operate outside of bankruptcy.

Effect of 2002 Rate Case Decisions

On March 29 and April 1, 2002, following the decision by the PUCN in NPC’s deferred energy rate case, S&P and Moody’s lowered SPPC’s unsecured debt ratings to below investment grade. On April 23 and 24, 2002, SPPC’s unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. The decision of the PUCN on May 29, 2002, on SPPC’s deferred energy application to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and November 30, 2001, did not result in any further downgrades of SPPC’s securities. As a result of the downgrades, SPPC’s ability to access the capital markets to raise funds is severely limited. Since SPR’s credit ratings were similarly downgraded, SPR’s ability to make capital contributions to SPPC also became severely limited.

For more detailed discussion of these effects please see SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

Accounts Receivable Facility

On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million. The receivables purchase facility was renewed on October 28, 2003, and expires on October 26, 2004. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and natural gas to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased receivables.

The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In additional to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either SPPC or SPR defaults (1) on the payment of indebtedness, or (2) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, SPPC’s facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of SPPC. In addition, the agreements contain a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC’s Term Loan Agreement, described below. SPR has agreed to guaranty SPPC’s performance of certain obligations as a seller and servicer under the receivables purchase facility.

SPPC has agreed to issue a $75 million General and Refunding Mortgage Bond upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of SPPC’s obligations as seller and servicer, plus certain interest, fees, and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of a SPPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage

securities, who could recover less on a pro rata basis than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond.

SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond.

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 September 30, 2003, $505.3 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 September 30, 2003, $499.3 million of SPPC’s General and Refunding Mortgage bonds were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70% of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds, and/or (iii) the principal amount of first mortgage bonds retired after April 8, 2002. On the basis of (i), (ii) and (iii) above, as of September 30, 2003, SPPC had the capacity to issue approximately $321.9 million of additional General and Refunding Mortgage securities not including $103 million of General and Refunding mortgage bonds that will be issued into escrow during November 2003 in connection with the Enron litigation. See Note 11 of the Condensed Notes to Consolidated Financial Statements for more information regarding the Enron litigation. 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 SPPC’s Term Loan Agreement and Receivable Purchase Facility Agreements limit the amount of additional indebtedness that SPPC may issue and the reasons for which such indebtedness may be issued. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility.

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.

Covenants

SPPC’s $100 million Term Loan Agreement, entered into on October 30, 2002, as amended on June 27, 2003, contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. The second covenant requires that SPPC maintain a consolidated interest coverage ratio for the four consecutive fiscal quarters ending with each of the following fiscal quarters of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002, March 31, 2003, and June 30, 2003, (ii) 1.85 to 1.0 for the fiscal quarter ended September 30, 2003, (iii) 2.00 to 1.0 for the fiscal quarter ended December 30, 2003, (iv) 2.25 to 1.0 for the fiscal quarter ended March 31, 2004, (v) 2.40 to 1.0 for the fiscal quarter ended June 30, 2004, (vi) 2.70 to 1.0 for the fiscal quarter ended September 30, 2004, and (vii) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter. As of September 30, 2003, SPPC was in compliance with these financial covenants. The Term Loan Facility, which is secured by SPPC’s $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005.

Cross Default Provisions

Certain financing agreements of SPPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPPC and SPR 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 or SPR 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 below:

• SPPC’s General and Refunding Mortgage Indenture, under which SPPC has $499.3 million of securities outstanding as of September 30, 2003, provides for an event of default if a matured event of default under SPPC’s First Mortgage Indenture occurs;

• SPPC’s Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC’s General and Refunding Mortgage Indenture ceases to be enforceable; and

Judgment Related Defaults

Limitations on Indebtedness

The terms of SPPC’s $100 million Credit Facility, which expires October 31, 2005, restrict SPPC from issuing additional indebtedness unless the debt issued is specifically permitted, which includes certain letter of credit indebtedness, certain capital lease obligations, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, and a limited amount of general indebtedness.

If SPPC is unable to access the capital markets to issue additional indebtedness to support its operations, including the purchase of fuel and power, and to refinance its existing indebtedness, whether due to lack of access to the capital markets, lack of regulatory authority, or restrictive covenants in its Term Loan Agreement, its ability to provide power and its financial condition will be adversely affected.

Sierra Pacific Resources (Holding Company)

The Consolidated Statements of Operations of SPR for the nine months ended September 30, 2003, include the operating results of the holding company. The holding company recognized an unrealized loss of $46.1 million on the derivative instrument associated with the issuance of $300 million of convertible notes and higher interest costs of $59.6 million in 2003 compared to $53.8 million in 2002, also due to the issuance of $300 million of convertible notes in February 2003.

Tuscarora Gas Pipeline Company

The Consolidated Statements of Income of Sierra Pacific Resources include the operating results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned subsidiary of SPR. For the three and nine month periods ended September 30, 2003, TGPC contributed $0.9 million and $2.7 million, respectively, in net income. For the three and nine month periods ended September 30, 2002, TGPC contributed $0.7 million and $2.3 million, respectively, in net income.

e·three

SPR began negotiations in the second quarter of 2003 to sell two of its subsidiaries, e·three and e·three Custom Energy Solutions, LLC (CES). Accordingly, at June 30, 2003, e·three and CES were reported as discontinued operations. Based on the expected selling price, a pre-tax loss on the disposal of $8.9 million was recognized for the six months ended June 30, 2003. On September 26, 2003, the sale of e·three and CES were completed. As a result of the final sales price, an additional pre-tax loss on disposal of $703,787 was recognized for the three months ended September 30, 2003. See Note 8 of Condensed Notes to Consolidated Financial Statements for additional information.

Sierra Pacific Communications

The Consolidated Statements of Income of Sierra Pacific Resources include the operating results of Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR. For the three and nine month periods ended September 30, 2003, SPC incurred net losses of $.8 million and $23.9 million, respectively. SPC incurred net losses of $1.1 million and $2.4 million, respectively, for the three and nine month periods ended September 30, 2002. Included in 2003 net losses for the nine month period is a pre-tax asset impairment charge of $32.9 million. See Note 8 of the Condensed Notes to Consolidated Financial Statements for discussion of the asset impairment charge.

REGULATORY MATTERS

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

Under federal law, the Utilities and Tuscarora Gas Pipeline Company (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.

Nevada Matters

Nevada Power Company 2001 Deferred Energy Case

On November 30, 2001, NPC filed an application with the PUCN seeking repayment 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.

On April 11, 2002, NPC filed a lawsuit in First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by NPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. NPC asserted that, as a result of the PUCN’s decision, NPC’s credit rating was reduced to below investment grade, SPR suffered a reduction in its equity market capitalization of approximately 40% and the disallowed costs are effectively imposed upon SPR’s shareholders. NPC further alleged that the order of the PUCN was: in violation of constitutional and statutory provisions; made upon unlawful procedure; affected by other error of law; clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; arbitrary and capricious, and characterized by abuse of discretion. NPC’s lawsuit requested that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize NPC to immediately establish rates that would allow NPC to recover its entire deferred energy balance of $922 million, with a carrying charge, over three years.

Various interveners in NPC’s deferred energy case before the PUCN filed petitions with the PUCN for reconsideration of the PUCN’s order, seeking additional disallowances of between $12.8 million and $488 million. On May 24, 2002, the PUCN issued an order denying any further disallowances and granted NPC the authority to increase the deferred energy cost recovery charge for the month of June 2002 by one cent per kilowatt-hour. This increase accelerated the recovery of the deferred balance by approximately $16 million for the month of June 2002 only.

On April 28, 2003, the court denied Nevada Power’s request for relief. NPC subsequently asked the court to reconsider its order. NPC’s request for reconsideration was denied on June 16, 2003. NPC filed appropriate notices of appeal with the Nevada Supreme Court on May 29, 2003, and June 16, 2003. The Supreme Court ordered the parties to submit to a settlement conference. The parties met on September 25, 2003, to discuss settlement. The parties then agreed to meet again in late October. In the event a settlement is not achieved, the case will be briefed and argued to the Nevada Supreme Court with a decision expected in late 2004.

Nevada Power Company 2002 Deferred Energy Case

The decision on this case was issued May 13, 2003, and authorized the following:

The new rates went into effect on May 19, 2003.

The BCP filed a Petition with the District Court of Clark County, Nevada, for Judicial Review of the PUCN Order on August 8, 2003, against PUCN, Case No. A471928. On September 8, 2003, the PUCN filed its answer to the BCP Petition. The PUCN response cites a number of affirmative defenses to the allegations contained in the BCP petition and asks that the court dismiss the BCP petition. The court has not ruled on this matter.

Nevada Power Company Demand Reduction Programs

On November 14, 2002, NPC filed an application with the PUCN seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, NPC requested a one-year recovery of approximately $1.9 million. This would result in an average 0.12% increase in NPC’s present rates. NPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2002 deferred energy case discussed above. The parties to the case subsequently negotiated a settlement agreement, which approved NPC’s request for cost recovery with the exception of a nominal disallowance. The stipulation was approved at the agenda meeting held April 4, 2003. The rate change went into effect on May 19, 2003, coincident with the deferred energy rate change discussed above.

Nevada Power Company 2003 Resource Plan

On July 1, 2003, NPC filed its 2003 Resource Plan with the PUCN. The Resource Plan was prepared in compliance with Nevada laws and regulations. The Resource Plan was prepared for the 20-year period from 2003 through 2022. The three-year action plan covers calendar years 2004, 2005, and 2006. The 2003 Resource Plan develops a comprehensive, integrated plan that considers customer energy requirements and proposes the resources to meet that requirement in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the plan is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s customers.

The 2003 Resource Plan is consistent with Governor Guinn’s 2001 Nevada Energy Protection Plan calling for the increased development of internal power generation to reduce dependence on volatile energy sources outside Nevada. The plan begins the process of taking control of energy supply and demand and reducing the dependence on others in order to provide price stability and electric reliability for customers.

As a step towards achieving this objective, NPC proposed building an 80 mega watt (MW) combustion turbine at the Harry Allen power plant site with an in-service date prior to the 2006 summer peak and a 520 MW combined cycle generating turbine, also at the Harry Allen power plant site, with a 2007 in-service date. Delivery of the energy from this new generation to NPC’s customers will require a reservation on the Harry Allen-to-Mead 500 kilovolt (kV) transmission line. The construction of this transmission project is required to fulfill existing wholesale transmission contractual obligations to Independent Power Producers located within NPC’s control area.

The three-year Action Plan describes the actions, specific projects, and budgets that NPC is proposing to implement during calendar years 2004, 2005, and 2006. NPC is seeking approval by the PUCN for the demand and supply side projects described in the plan. This three-year strategy is based on analyses of prevailing market dynamics and supply and demand fundamentals within the energy sector. NPC is therefore seeking PUCN approval of action items, including the following:

• Approval of NPC’s electric load forecast as being a fair representation of expected loads during the 20-year period spanning 2003 through 2022.

• Approval of NPC’s fuels price forecasts as being a fair representation of expected range of prices during the same 2003 through 2022 period.

• Approval of NPC’s plan to reserve up to 650 MW of additional native load transmission rights on the Centennial Transmission Project following the construction of the Harry Allen-to-Mead 500 kV transmission line, the third phase of the project.

• Approval for re-conductoring the 230 kV Mead system that would increase system import by 450 MW at an estimated cost of $24 million.

• Approval to construct a combustion turbine generating plant at the Harry Allen power plant site prior to the summer peak of 2006 at an estimated cost of $44.1 million.

• Approval to construct a combined cycle generating plant including duct burners rated at 520 MW. The unit is planned for the Harry Allen power plant site with an in-service date prior to the 2007 summer peak, at a cost of $414.7 million.

• NPC will submit long-term transmission service requests to other transmission owners for capacity from the Palo Verde region to Mead. Long-term transmission capacity has been unavailable from the Palo Verde region to Mead. These requests will likely result in system impact and facility studies by these transmission owners. NPC is requesting PUCN approval of the estimated $100,000 for the aforementioned studies.

• Approval to spend $9.2 million, $9.3 million, and $9.3 million for calendar years 2004, 2005, and 2006, respectively, devoted to demand-side programs. The programs were developed in a collaborative effort, based upon input from various interested parties.

• Approval of the recommended natural gas hedging strategy for 2004.

• Exemption from the avoided cost filing requirements set forth in Nevada Administrative Code section 704.8783 based upon the use of a competitive bidding process to fill mega watts available to Qualifying Facilities as a result of the renewable energy request for proposal (RFP) and long-term purchase obligation RFP for up to 2,500 MW.

• Approval for a plant life assessment of NPC’s existing power plants, at a cost of $500,000 per each year of the Three-Year Action Plan.

In addition, the Action Plan includes the following action items:

• Issue an RFP for long-term purchase power contracts to fill a substantial portion of remaining capacity requirements expected for 2004-2006. The results of the RFP and any executed contracts will be filed with the PUCN for approval.

• Issue an RFP to meet the Renewable Energy Portfolio Standard through 2007 as adopted and passed into law by the Nevada State Legislature. NPC proposes to execute the agreements and bring the signed agreements to the PUCN for approval as a compliance item to this plan.

Intervenor testimony was received on September 19, 2003. PUCN Staff was generally supportive of the plan as filed. Issues raised by intervenors included the Company’s proposed reservation of 650 MW of transmission capacity for future native load uses, the Company’s gas hedging strategy, and the ability to finance the Company’s preferred plan.

The PUCN conducted hearings on NPC’s Resource Plan on October 16, 2003. The PUCN approved an order on NPC’s Resource Plan on November 12, 2003. In general, the order approved NPC’s various requests made in its filing and also imposed additional requirements for various briefings, and required amendments to the plan if there are delays in the combined cycle units construction, issues with transmission reservations, or difficulties financing the plan. As such, NPC may need to expend up to approximately $500 million prior to the summer of 2007 for the construction and/or acquisition of generation facilities. If NPC is unable to provide this amount with internally generated funds, it may need to access the capital markets to do so. See NPC’s Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources for a discussion of NPC’s financial condition and limitations on NPC’s ability to issue additional indebtedness.

Nevada Power Company 2003 General Rate Case

Nevada Power Company filed its biennial General Rate Case on October 1, 2003, as required by statute (NRS 704.110(3)). NPC’s analysis and presentation of the costs of providing electric service (exclusive of purchased fuel and purchased power) indicate that it is necessary to increase the revenue requirement for general rates by $142 million annually. Factors supporting the requested revenue increase include, (1) investments in infrastructure of $433 million since the last general rate case, (2) a requested Return on Equity (ROE) of 12.4% and Rate of Return (ROR) of 10.0%, (3) recovery of the costs to merge NPC and Sierra Pacific, (4) recovery of the costs NPC spent on the generation divestiture project, which was cancelled by legislation, (5) a return on the cash balances NPC must maintain to provide continuous service, and (6) increased operating costs.

NPC is recommending that the Commission authorize a deferred collection of the requested increase so that for nine months commencing April 1, 2004, annualized general revenue would increase $50 million. Beginning January 1, 2005, annualized general revenue would then increase by $92 million plus the amount necessary to return $76 million over the following 15 months. This $76 million is the estimated amount being deferred ($73 million plus interest of $3 million) during the prior nine month period between April 1, 2004 and January 1, 2005. Hearings are scheduled to begin February 3, 2004.

Sierra Pacific Power Company 2003 Deferred Energy Case

• A reduction in the current deferred energy balance of $45 million leaving a balance payable to customers of approximately $29.6 million.

• A two-year amortization of the amount payable returning one third of the balance in the first year (approximately $9.9 million), and two thirds of the balance the second year (approximately $19.7 million).

• Discontinue carrying charges on deferred energy balances that SPPC is already collecting from customers and on the $29.6 million amount payable as a result of the agreement.

• Maintain the currently effective Base Tariff Energy Rate.

• SPPC maintains the rights to claim the cost of terminated energy contracts in future deferred filings.

• Parties agreed that with the $45 million reduction the remaining costs for purchasing fuel and power during the test year were prudently incurred and are just and reasonable.

• SPPC and the Bureau of Consumer Protection agreed to file a motion to dismiss the civil lawsuits filed in relation to the 2001 SPPC deferred energy case.

The agreement was approved by the PUCN at the agenda meeting held on May 19, 2003, and the new rates went into effect on June 1, 2003.

Sierra Pacific Power Company Demand Reduction Programs

On January 14, 2003, SPPC filed an application with the PUCN seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, SPPC requested a one-year recovery of approximately $0.9 million, which would result in an average 0.12% increase in SPPC’s rates. The parties to the case subsequently negotiated a settlement agreement that is expected to be approved by the PUCN coincident with its 2003 deferred energy ruling. The agreement called for complete recovery of the $0.9 million balance. The agreement, allowing recovery of the entire balance, was signed by all parties and approved at the PUCN’s May 19, 2003, agenda meeting. Rates went into effect June 1, 2003, coincident with the deferred energy rate change discussed above.

Annual Purchased Gas Cost Adjustment (SPPC)

In addition, SPPC filed on May 15, 2003, to replace the Variable Rate Mechanism (VRM) component of the Base Tariff General Rate (BTGR) with a new component of $0.00756 per therm. This new adjustment would allow recovery over a 12-month period of a balance, which has accrued in the VRM deferred account. This request would result in an increase of approximately 1% in customer rates. Both of these dockets were consolidated with the docket for the Liquid Petroleum Gas Cost Adjustment below.

SPPC, the PUCN Staff, and the Bureau of Consumer Protection agreed upon a Stipulation for all three dockets, which was approved by the PUCN Commission on October 1, 2003.

Overall, rates for SPPC’s natural gas customers decreased by approximately 3%. SPPC agreed to write off $500,000 in its VRM account and the remaining balance of $446,603 will be recovered over a twelve-month period through an increase in the BTGR of $0.00519. The Parties agreed that the new BAA will be amortized over two years with 67% of the balance recovered in the first year, and 33% of the balance recovered in the second year. The BAA rate for the first year will be a credit of $0.06448 per therm. The BAA rate for the second year will be a credit of $0.03176 per therm. A BPGR of $0.66375 per therm was approved, an increase from the previous BPGR of $0.05316 per therm. The new rates were implemented November 1, 2003.

Liquid Petroleum Gas Cost Adjustment (SPPC)

On May 15, 2003, SPPC filed an application to adjust rates for its liquid petroleum gas (LPG) distribution company. In the application, SPPC asked for an increase of $0.08513 per therm to its current LPG rate of $0.65952 per therm and requested a new BAA of $0.08864 per therm. The proposed BAA rate would amortize the current balance over three years. This rate request would result in an increase of approximately 18% in customer rates. This docket was consolidated with the annual Purchased Gas Cost Adjustment above.

The PUCN Commission approved a Stipulation on October 1, 2003, which had been agreed upon by SPPC, the PUCN Staff, and the Bureau of Consumer Protection for this docket along with the Purchased Gas Cost Adjustment and VRM dockets above.

As a result of the Stipulation, rates for SPPC’s liquefied petroleum gas customers were increased by approximately 27%. The BPGR was increased to $0.78060 per therm and the Parties agreed to amortize the BAA over two years, resulting in a new BAA of $0.09797 per therm.

Senate Bill 8

Senate Bill 8 recently passed in a Special Session of the Nevada Legislature (SB 8) provides for a modified business tax based upon payroll. Section 187 of SB 8 provides that a public utility may increase its previously approved rates by an amount that is reasonably estimated to produce an amount of revenue equal to the amount of any tax liability incurred by the public utility as a result of the act. Both NPC and SPPC implemented increased rates for recovery of this tax on October 1, 2003.

Customers File to be Served by New Providers under NRS 704B (AB 661)

AB 661, passed by the Nevada legislature in 2001 and incorporated into Nevada Revised Statutes as NRS 704B, allows commercial and governmental customers with an average demand greater than 1 MW to select new energy suppliers. The Utilities would continue to provide transmission, distribution, metering, and billing services to such customers. NRS 704B requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Utilities, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. Management believes that those customers securing energy from new energy suppliers may help alleviate the Utilities’ need to access energy from potentially volatile wholesale energy markets. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the Utility. Customers wishing to choose a new supplier must provide 180-day notice to the Utilities.

Thirteen NPC customers have filed applications for departure. These applications total approximately 350 MW of peak load. In twelve of these applications, stipulations have been reached that addressed all issues except treatment of Base Tariff General Rate (BTGR) revenue impacts arising from departure. The PUCN has issued a compliance order for these twelve applications that will allow the customers to depart upon completion of items in the compliance order. Eight of these twelve customers elected not to make compliance filings and will remain full requirements customers of NPC and their applications have lapsed. Several of these eight customers filed notice of their intent to file new applications; however, to date, no new applications have been filed. While four customers made their required compliance filings, the PUCN determined that these customers did not comply with the provisions of their compliance orders. Consequently all of their approvals have been rescinded and, at this time, none of these customers have reapplied for departure. The remaining applicant withdrew their application. At the present time there are no applications pending before the commission.

Regulatory Filing Schedule

Nevada Power Company will be filing a Deferred Rate Case by November 14, 2003 and Sierra Pacific Power Company will be filing a General Rate Case by December 1, 2003.

California Matters (SPPC)

Rate Stabilization Plan

SPPC serves approximately 44,500 customers in California. On June 29, 2001, SPPC filed with the California Public Utilities Commission (CPUC) a Rate Stabilization Plan, which included two phases. Phase One, which was also filed June 29, 2001, was an emergency electric rate increase of $10.2 million annually or 26%. The increase was applicable to all customers except those eligible for low-income and medical-needs rates and went into effect July 18, 2002.

Phase Two of the Rate Stabilization Plan was filed with the CPUC on April 1, 2002, and includes a general rate case and requests the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. Phase Two also includes a proposal to terminate the 10% rate reduction mandated by AB 1890, but does not include a performance – based rate-making proposal. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually.

On December 19, 2002, SPPC filed an amendment to the Phase Two application reducing the requested increase by $4.1 million to $4.8 million or 9.2% annually. SPPC agreed to make certain changes to the application and file the amendment following discussions with the CPUC Office of Ratepayer Advocates. In February 2003, the Office of the Ratepayer Advocates (ORA) filed testimony on cost of service proposing to reduce SPPC’s request by $3.2 million resulting in a $1.6 million increase or 3.3%. On March 14, 2003, SPPC filed rebuttal testimony. On March 10, 2003, the ORA filed testimony on revenue allocation and rate design and on April 2, 2003, SPPC and the California Ski Areas Association filed rebuttal testimony. Hearings were held on April 9, 2003. Opening and reply briefs were filed on May 21, 2003, and June 6, 2003, respectively. Also on June 6, 2003, a settlement agreement was filed resolving all issues except rate design, reflecting an increase of $3.02 million or 5.8%. A decision by the CPUC regarding the Energy Cost Adjustment Clause is expected in late 2003.

California Assembly Bill 1235

On September 24, 2002, the Governor of California signed into law Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235 effectively amends previous California legislation (AB 6) that prevented private utilities from selling any power plants that provide energy to California customers until 2006. AB 1235 provides an exemption for the four “run-of-the-river” hydroelectric plants that SPPC sold to TMWA as part of the sale of its water business in June 2001.

On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC issued a ruling that the California Environmental Quality Act applies to this proceeding and SPPC must supplement the application with a certified environmental document. SPPC has begun informal discussions with the CPUC on the environmental issues and cannot yet predict the outcome of this proceeding. On April 17, 2003, the CPUC issued a ruling dismissing the application without prejudice. The decision allows SPPC to re-file the application including an environmental assessment and on September 26, 2003, SPPC filed a new application. That application is currently under review by the CPUC.

FERC Matters (NPC, SPPC)

In December 2001, the Utilities filed ten wholesale-purchased power complaints with the FERC under Section 206 of the Federal Power Act seeking to reduce prices of certain forward power purchase contracts that the Utilities entered into prior to the price caps established by the FERC during the western United States utility 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 have already paid the full contact price for all power actually delivered by these suppliers, but are contesting claims made for terminated power suppliers, including those terminated by Enron.

The Administrative Law Judge (ALJ) overseeing the Utilities’ complaints and proceedings under Section 206 of the Federal Power Act issued an initial decision on December 19, 2002, which stated that the Utilities’ complaints did not meet the public interest standard of proof, which the ALJ believed applied to the reformation of their contracts. NPC, SPPC, and other parties to these proceedings filed Briefs on Exceptions to the ALJ’s initial order with the FERC.

On June 26, 2003, FERC dismissed the Utilities’ Section 206 complaints on a two-to-one vote essentially 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. In that order, FERC also determined that it would not deem the order final and conclusive as to any of the Utilities’ liability to Enron for purchase power contracts terminated by Enron. FERC indicated that any challenges to those contracts on the

basis of market manipulation or fraud would be based on the evidence presented in that proceeding. On July 28, 2003, the Utilities filed a petition for rehearing at the FERC requesting that the FERC either reconsider or rehear the case. The petition cited several grounds for rehearing, including that the public interest standard did not apply but that even if it did apply the Utilities had satisfied that standard as well as the less onerous just and reasonable standard which the Utilities contend does apply to the case. On November 10, 2003, the FERC issued an Order on Requests for Rehearing and Clarification, which has reaffirmed the June 26, 2003 decision (by the same two-to-one margin), which decision now perfects the Utilities’ right to seek judicial review. The Utilities intend to pursue available appeals of this matter. Under applicable statutes, the Utilities may seek judicial review before the United States Court of Appeals for the District of Columbia Circuit or the Ninth Circuit.

On September 26, 2003, the Bankruptcy Court entered an order granting Enron’s motion for summary judgment on its liquidated damage claim and dismissed the Utilities’ counterclaims. The judgment requires 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 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. As a result, NPC and SPPC recognized additional contract termination reserves for interest, based on the ordered prejudgment rate of 12%, of $27.8 million and $12.4 million, in the third quarter of 2003, respectively. Also, NPC and SPPC recorded additional contract termination reserves for liquidated damages of $6.6 million and $2.1 million, in the third quarter of 2003, respectively. The courts’ order provides that until paid, the amounts owed by the Utilities will accrue interest post-judgment at a rate of 1.21% per annum. The court’s judgment ordered that all funds be held in escrow pending FERC’s resolution of the Utilities’ petition for rehearing and/or reconsideration on FERC’s June 25, 2003, dismissal of the Utilities’ 206 complaints against Enron. See SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002 for additional information regarding the Enron litigation.

On October 6, 2003, the Utilities filed a new FERC Section 206 complaint against Enron Power Marketing, Inc. (Enron) to prevent Enron from obtaining a final judgment in the Bankruptcy Court case and/or prevent enforcement of any right to collect its termination payments until FERC has had a chance to review the complaint. The new complaint has been designated as docket EL04-1. On October 27, 2003, Enron filed its answer to the Utilities’ complaint and the matter is pending.

Enron was found by the FERC earlier this year to have unlawfully manipulated the Western energy market, engaging in fraud, deception and other actions that created power market prices that were unjust and unreasonable. Prior and subsequent to the FERC ruling, numerous Enron employees pled guilty to related criminal charges.

The 206 complaint in EL04-1 asks FERC to issue an order to preserve the status quo by prohibiting Enron from enforcing the termination payment obligations set forth in the judgment until such time as FERC has an opportunity to review the merits of the Utilities’ claims raised in their new FERC Section 206 complaint. The complaint further asks that FERC find that Enron’s actions violated the terms of tariff language rendering Enron unable to collect termination payments; that Enron violated federal law, including the Federal Power Act, and breached FERC’s regulations and power tariffs governing the transactions. In addition, the complaint asks FERC to: (a) assert its jurisdiction over the issue of whether Enron may lawfully claim rights under the power deals to be paid for not providing power that it could not provide anyway; (b) issue an order to preserve the status quo by prohibiting Enron from enforcing the termination payment obligations set forth in the judgment until such time as FERC has an opportunity to review the merits of the Utilities’ claims raised in their new FERC Section 206 complaint; (c) find that the applicable rules to do not permit the sort of maneuver to create a windfall that Enron has attempted; and (d) find that, even if hypothetically Enron is technically entitled to a payment, it is neither equitable nor in the public interest for the Utilities to be required to pay Enron an additional award in excess of $300 million. At this time, NPC and SPPC are unable to predict either the outcome or timing of a decision in this matter.

On October 8, 2003, the Nevada Attorney General’s office, through its Bureau of Consumer Protection, intervened on behalf of Nevada citizens, joining NPC and SPPC in opposing Enron’s actions through the Bankruptcy Court. On October 29, 2003, United States Senators Reid and Ensign of Nevada also filed an intervention joining NPC and SPPC in opposing Enron’s claims to termination payments.

For more information regarding the Section 206 proceedings, please see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulation and Rate Proceedings – FERC Matters – FERC 206 Complaints, in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

Open Access Transmission Tariff

On September 27, 2002, the Utilities filed with the FERC a revised Open Access Transmission Tariff (OATT) designated Docket No. ER02-2609-000. The purpose of the filing was to implement changes that are required to implement retail open access in Nevada. The Utilities requested the changes to become effective November 1, 2002, the date retail access was scheduled to commence in Nevada in accordance with provisions of AB 661, passed in the 2001 session of the Nevada Legislature.

On October 11, 2002, the Utilities filed with the FERC revised rates, terms, and conditions for ancillary services offered in the OATT designated Docket No. ER03-37-000. On November 25, 2002, FERC combined Docket No. ER02-2609-000 with Docket No. ER03-37-000 and suspended the rates in Docket No. ER03-37-000 for a nominal period and made them effective subject to refund on January 1, 2003. On July 1, 2003, FERC approved the offer of settlement that was filed on May 12, 2003. The Utilities have issued refunds for amounts collected in excess of settlement rates and filed a report of such refunds at the FERC as instructed in the July 1 letter order. The Utilities have not yet received final approval of the refund report.

Other

On September 11, 2003, the Utilities filed with the FERC revised rates for transmission service offered by its subsidiary Nevada Power Company under Docket No. ER03-1328. The purpose of the filing is to update rates to reflect recent transmission additions and to improve rate design. FERC issued an order on November 7, 2003, setting rates effective November 10, 2003, subject to refund and setting issues for public hearing.

The FERC Staff has recommended that certain market participants identified in a Cal ISO report released January 6, 2003, including SPPC, be directed to show cause why their behavior did not constitute gaming in violation of the Cal ISO and Cal PX tariffs. In its report, the Cal ISO indicated that it was unclear as to the reason SPPC received certain revenues in the amount of approximately $6 thousand. SPPC was one of the over 30 market participants included in the Staff’s recommendation. On April 7, 2003, SPR submitted documentation to the FERC demonstrating that SPPC did not engage in gaming in violation of the Cal ISO or Cal PX tariffs, nor in the manipulation of the Western energy market. The Cal ISO revised its report, removing SPPC’s name altogether, but other California parties’ testimony included SPPC’s name for the same transactions. On June 25, 2003, the FERC issued a show cause order allowing SPPC to justify its actions on these same transactions. SPPC is actively pursuing the issue to clear its name in this proceeding and the FERC Trial Staff has filed a motion to dismiss SPPC from the proceedings. The Trial Staff’s motion is pending.

On July 10, 2003 Pinnacle West Energy Corporation filed a complaint (designated Docket No. EL03-209-000) with the FERC requesting that Nevada Power Company be directed to abide by Section 17.7 of its open access transmission tariff (OATT) and provide it with a one year extension for the commencement of transmission service pursuant to a transmission service agreement (TSA) between Pinnacle West and Nevada Power. On July 18, 2003, Southern Nevada Water Authority (SNWA) filed a similar complaint (designated Docket No. ER03-213-000) requesting the same relief to a TSA between SNWA and Nevada Power. Nevada Power answered both complaints and asserted that if new facilities have been constructed to provide service to a transmission customer, then an extension of the commencement of service can be provided only if the transmission customer pays Nevada Power’s full carrying charges on the newly constructed facilities. On August 21, 2003, in Docket No. ER03-1236-000, Sierra Pacific Power Company and Nevada Power Company filed an amendment to Section 17.7 of the Sierra Pacific Resources Operating Companies’ OATT. The companies assert that the filing is necessary to address requests for an extension of the commencement of service over Nevada Power’s newly constructed Centennial Project. These issues are currently being addressed through FERC settlement procedures.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of loss arising from adverse changes in market rates and prices, such as interest rates and commodity prices. Our primary exposures to market risk are interest rate risk associated with Long-Term Debt, commodity price risk associated with fuel and purchased power contracts, forwards and options held by the Utilities, the credit risk associated with energy and financial service company counterparties from which the Utilities procure fuel and purchase power, and until August 11, 2003, equity price risk associated with SPR’s Convertible Notes.

Interest Rate Risk

SPR has evaluated its risk related to financial instruments whose values are subject to market sensitivity, such as fixed and variable rate debt and preferred trust securities obligations. As shown in SPR’s Form 10-K for the year ended December 31, 2002, the fair market value of SPR’s consolidated Long-Term Debt and preferred trust securities was $3.372 billion, as of December 31, 2002. As of September 30, 2003, the fair market value of SPR’s market-sensitive financial instruments had increased approximately 8.58% to $3.661 billion. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt or preferred obligations of the same remaining maturities.

Long-Term Debt as of September 30, 2003 (dollars in thousands):


		September 30, 2003

		Expected Maturities Amounts								Weighted Avg Int Rate			Fair Market Value

Expected Maturity Date		NPC (1)		SPPC		SPR (2)		Consolidated		Consolidated			Consolidated

Fixed Rate
	2003	$	4	$	19,103	$	20,315	$	39,422		6.86	%
	2004		130,013		83,400		—		213,413		6.05	%
	2005		15		100,400		300,000		400,415		9.16	%
	2006		15		52,400		—		52,415		6.71	%
	2007		17		2,400		240,218		242,635		7.91	%
Thereafter			1,727,720		759,913		232,277		2,719,911		7.82	%

Total Fixed Rate		$	1,857,784	$	1,017,617	$	792,810	$	3,668,210				$	3,546,231


Variable Rate
2003		$	—	$	—	$	—	$	—
	2004		—		—		—		—
	2005		—		—		—		—
	2006		—		—		—		—
	2007		—		—		—		—
Thereafter			115,000		—		—		115,000		1.74%	(3)

		$	115,000	$	—	$	—	$	115,000				$	115,000

Total		$	1,972,784	$	1,017,616	$	792,810	$	3,783,210				$	3,661,231

(1) Included in NPC’s “Thereafter” amount is $188,872 of Preferred Trust Securities, reclassified to Long-Term Debt as the result of the adoption of SFAS No. 150. See Note 4, Long-Term Debt.

(2) $142,180 of SPR’s Convertible Notes due 2010 that were presented as current on the June 30, 2003, Form 10Q, have been reclassified, to “Thereafter” following the shareholder vote in August 2003, which gave SPR the ability to settle the conversion of its Convertible Notes entirely in shares rather than partially in cash. See Note 4, Long-Term Debt.

(3) Weighted average daily rate for month ended September 30, 2003.

Equity Price Risk

In connection with SPR’s issuance of its Convertible Notes, the conversion option, until August 11, 2003, was treated as a cash-settled written call option separated from debt and accounted for separately as a derivative instrument in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The fair market value of the derivative was recorded as a liability in SPR’s financial statements with changes in the fair value of the derivative reported in earnings in the period of the change.

The fair value of the conversion option derivative is determined using a pricing model that incorporates information and assumptions such as SPR’s stock price, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the derivative.

Issue No. 00-19 of the Emerging Issues Task Force of the FASB (“EITF”), “Accounting for Derivative Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock,” provides for the recording of the fair value of the derivative in equity, if all applicable provisions of EITF Issue No. 00-19 are met. On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes, which satisfied the provisions of EITF Issue No. 00-19. Accordingly, the fair value of the derivative of $118 million recorded in current liabilities was reclassified to equity on the date of the shareholder vote. In addition, EITF Issue No. 00-19 indicates that subsequent changes in fair value should not be recognized as long as the derivative remains classified in equity. As long as the derivative remains classified in equity, SPR will not mark this instrument to market. Accordingly, no unrealized gains or losses will be recorded in earnings subsequent to August 11, 2003. The previous changes in fair value of the derivative instrument recorded in earnings will not be reversed.

Commodity Price Risk

See the Annual Reports on Form 10-K of SPR, NPC, and SPPC for the year ended December 31, 2002, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. As of September 30, 2003, the Utilities had outstanding transactions with 38 energy and financial services companies. The Utilities’ credit risk associated with these transactions was approximately $4.1 million as of September 30, 2003. This credit risk represents the difference between the contract price of energy that the Utilities have secured with energy and financial services companies and the higher market prices as of September 30, 2003. In the event that the energy providers were unable to deliver under the contracts, it would be necessary for the Utilities to purchase alternative energy at the higher market price.

ITEM 4. CONTROLS AND PROCEDURES

SPR, NPC, and SPPC maintain disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), designed to ensure that they are able to collect the information required to be disclosed in the reports they file with the Securities and Exchange Commission (SEC), and to process, summarize, and disclose this information accurately and within the time periods specified in the rules of the SEC. The chief executive officer and chief financial officer of each of SPR, NPC, and SPPC have reviewed and evaluated SPR’s, NPC’s, and SPPC’s disclosure controls and procedures as of September 30, 2003, (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the disclosure controls and procedures of SPR, NPC, and SPPC are effective in bringing to their attention on a timely basis material information relating to SPR, NPC, and SPPC required to be included in periodic filings under the Exchange Act.

There have not been any significant changes in the internal controls over financial reporting of SPR, NPC, and SPPC that occurred during the quarter ended September 30, 2003, that materially affected, or were reasonably likely to materially affect SPR’s, NPC’s, and SPPC’s internal controls over financial reporting.

PART II —OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Item 3 of SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002, Note 18 to SPR’s consolidated financial statements contained in that report, and Note 11 to SPR’s consolidated financial statements contained in this report for a description of pending legal proceedings. Except as set forth below, there are no additional material legal proceedings or material developments with respect to previously reported proceedings involving SPR, NPC, or SPPC.

Sierra Pacific Resources and Nevada Power Company

Lawsuit Against Merrill Lynch and Allegheny Energy, Inc.

On April 2, 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc., and Allegheny Energy Supply Company, LLC (collectively, Allegheny) seeking actual and punitive damages in excess of $850 million and demanding a jury trial for all claims triable by jury. The complaint alleges that the Merrill Lynch defendants engaged in misrepresentation, suppression and concealment, breach of fiduciary duty, wrongful hiring and supervision of Daniel Gordon, and breach of contract and alleges that both Merrill Lynch and Allegheny engaged in intentional interference with contractual and prospective advantage, conspiracy and racketeering (in violation of Nevada Revised Statutes Section 207.470). The complaint also alleges that the improper behavior of Merrill Lynch and Allegheny was the direct and proximate cause of the March 2002 decision by the PUCN to disallow $180 million of rate adjustments in NPC’s 2001 deferred energy accounting adjustment rate application.

On June 23, 2003, Merrill Lynch and Allegheny filed motions asking the court to dismiss SPR and NPC’s complaint. Briefing on the motions to dismiss closed on August 12, 2003, and the matter is currently pending. At this time, SPR and NPC are unable to predict either the outcome or timing of a decision in this matter.

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 natural gas providers El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company, Sempra Energy, Southern California Gas Company (SoCal), San Diego Gas and Electric Company (SDG&E), Dynegy Holdings, Inc., Dynegy Energy Services, Inc., and Does 1-100, seeking $600 million in total damages. Reliant was added as a defendant in a subsequently filed amended complaint. The amended complaint alleges, among other things, that as a result of the defendants’ conspiracies and fraudulent behavior, SPR and NPC were forced to enter into natural gas purchase contracts “at artificially high, supracompetitive prices.” The amended complaint further states that between 1996 and 2001, certain of the defendants and their subsidiaries conspired, in secret meetings, to decrease competition by restricting the amount of pipeline capacity and fuel available to NPC while other defendants decreased natural gas supplies and drove up prices by illegally withholding pipeline capacity, maintained control over output and prices by manipulating natural gas price indexes, and harmed market competition and the plaintiffs by driving up prices and increasing the volatility of natural gas supplies. SPR and NPC assert (among other things) claims for federal and state antitrust violations, fraud, breach of contract, unjust enrichment, and violation of the state and federal RICO Acts. In September 2003, SoCal, SDG&E, and El Paso Corporation moved to dismiss the amended complaint because of a lack of personal jurisdiction. Reliant moved to compel arbitration. All of the remaining defendants (as well as Reliant, SoCal, and SDG&E) filed motions to dismiss for failure to state a claim. SPR and NPC must respond by November 11, 2003. At this time, SPR and NPC are unable to predict either the outcome or timing of a decision in this matter.

Disputes with Purchased Power Providers

In June 2003, Reliant Energy submitted a comprehensive settlement proposal to NPC proposing a settlement of NPC’s termination payment obligation arising out of Reliant’s May 2002 termination of its purchase power contracts with NPC. NPC denies that it owes Reliant any money under these contracts. Mediation of this claim occurred in 2002 and was not successful.

Neither party has requested arbitration nor commenced litigation over this dispute, and the parties are continuing discussions. See Note 11 to SPR’s consolidated financial statements contained in this report for additional information regarding Reliant’s claims.

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

Nevada Power Company

Morgan Stanley Proceedings

On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG requested that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claimed that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC’s contract claims and defenses. In March 2003, the arbitrator overseeing the arbitration proceedings dismissed MSCG’s demand for arbitration and agreed that the issues raised by MSCG were not calculation issues subject to arbitration and that NPC’s contract defenses were likewise not arbitrable.

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

A 2003 Special Meeting of the Stockholders of Sierra Pacific Resources was held at 10:00 a.m., Pacific Daylight Time, on Monday, August 11, 2003, at its headquarters located at 6100 Neil Road, Reno, Nevada.

At the meeting shareholders approved the potential issuance of up to 42,736,920 additional shares of SPR’s Common Stock in lieu of the cash payment component of the conversion price of SPR’s 7.25% Convertible Notes due 2010. Through the close of business February, 14, 2010, each $1,000 principal amount of the Notes are convertible, at SPR’s election, into: (1) 76.7073 shares of Common Stock plus an amount of cash equal to the then market value of 142.4564 shares of our Common Stock, subject to adjustment upon the occurrence of certain dilution events; or (2) 219.1637 shares of our Common Stock, subject to adjustment upon the occurrence of certain dilution events. For further information regarding the terms of the Convertible Notes, see Note 4. Long-Term Debt.

The voting results are shown below:

For

Withheld

Abstain

Potential 42,736,920 additional share issuance

58,709,590

31,705,421

1,289,876

approval.

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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

Nevada Power Company


Exhibit 4.1	Officer’s Certificate establishing the terms of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G. due 2013.

Exhibit 4.2	Form of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G. Due 2013.

Sierra Pacific Power Company


Exhibit 4.3	Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series D, due 2004.

Exhibit 4.4	Form of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series D, due 2004

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


Exhibit 10.1		Employment Agreement for Walter M. Higgins

Exhibit 31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K:

Form 8-K dated August 8, 2003, filed by SPR, NPC – Item 5, Other Events

Disclosed, and included as an exhibit, NPC’s press release, dated August 8, 2003, announcing that it will privately offer $350 million principal amount of its General and Refunding Mortgage Notes, Series G, with an anticipated maturity of 10 years.

Form 8-K dated August 11, 2003, filed by SPR, NPC, and SPPC – Item 5, Other Events

Disclosed, and included as an exhibit, SPR’s press release, dated August 11, 2003, announcing it had received, at a special shareholder meeting, shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of the cash payment component of the conversion price of SPR’s 7.25% Convertible Notes due 2010.

Form 8-K dated August 13, 2003, filed by SPR, NPC – Item 5, Other Events

Disclosed, and included as an exhibit, NPC’s press release, dated August 13, 2003, announcing it had priced a private offering of $350 million principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013.

Form 8-K dated August 28, 2003, filed by SPR, NPC, and SPPC – Item 5, Other Events

Disclosed, and included as an exhibit, SPR’s press release, dated August 28, 2003, announcing that the Bankruptcy Court for the Southern District of New York rendered a decision in Enron’s bankruptcy proceedings granting Enron Power Marketing Inc.’s motion for summary judgment with respect to Enron’s claims for terminated contracts.

SIGNATURES

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


		Sierra Pacific Resources

		(Registrant)

Date: November 13, 2003	By:	/s/ Richard K. Atkinson

		Richard K. Atkinson Vice President Chief Financial Officer (Principal Financial Officer)

Date: November 13, 2003	By:	/s/ John E. Brown

		John E. Brown Vice President Controller (Principal Accounting Officer)

		Nevada Power Company

		(Registrant)

Date: November 13, 2003	By:	/s/ Richard K. Atkinson

		Richard K. Atkinson Vice President Chief Financial Officer (Principal Financial Officer)

Date: November 13, 2003	By:	/s/ John E. Brown

		John E. Brown Vice President Controller (Principal Accounting Officer)

		Sierra Pacific Power Company

		(Registrant)

Date: November 13, 2003	By:	/s/ Richard K. Atkinson

		Richard K. Atkinson Vice President Chief Financial Officer (Principal Financial Officer)

Date: November 13, 2003	By:	/s/ John E. Brown

		John E. Brown Vice President Controller (Principal Accounting Officer)

(1)		Credits represent over-collections, that is, the extent to which gas or fuel and purchased power costs recovered through rates exceed actual gas or fuel and purchased power costs.

(2)		Amounts related to terminated suppliers are discussed in Note 11, Commitments & Contingencies and Note 17, Commitments and Contingencies, of Notes to Financial Statements in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2002.

	•		those payments do not exceed $60 million for any one calendar year,

	•		those payments comply with any regulatory restrictions then applicable to NPC, and

	•		the ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1.

	•		there are no defaults or events of default with respect to the Series E Notes or the Series G Notes,

	•		NPC has a ratio of consolidated cash flow to fixed charges for NPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2.0 to 1, and

	•		the total amount of such dividends is less than:

	•		the sum of 50% of NPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the applicable series of Notes, plus

	•		100% of NPC’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 NPC, plus

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

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

	•		50% of SPPC’s Consolidated Net Income for the period commencing January 1, 2003, and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus

	•		the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period.

	1.		Income from continuing operations and income applicable to common stock for the three months ended September 30, 2003 were adjusted by adding back interest expense of $4.7 million (net of tax) and subtracting the unrealized gain on derivative of $40 million (net of tax), included in net income for the three months ended September 30, 2003.

	2.		Weighted average number of shares outstanding for the three months ended September 30, 2003 was adjusted by adding 65,749,110 shares for the Convertible Notes as of the beginning of the period.

	3.		The denominator does not include anti-dilutive stock equivalents for the Stock Option Plan and Corporate PIES due to conversion prices being higher than market prices at September 30, 2003. The amounts that would be included in the calculation if the conversion price were met would be 1.5 million shares for the Stock Option Plan and 17.3 million shares for Corporate PIES.

	4.		Plan terminated in 2002.

	5.		New plan for 2003.

	6.		For the nine months ended September 30, 2003 and 2002 the weighted average number of shares after dilution excludes shares of 65,814,279 and 33,004, respectively, for stock options, executive long term incentive plan — performance shares, executive long term incentive plan — restricted shares, non-employee Director stock plan, Employee stock purchase plan and convertible notes as they would be anti-dilutive.

	•		recovery of $147.6 million, with a carrying charge, and a $48.1 million disallowance;

	•		a three-year amortization of the balance commencing on May 19, 2003;

	•		a reduction in the Base Tariff Energy Rate (BTER) to an effective non-residential rate of $0.04322 per kWh, and an effective residential rate of $0.04186 per kWh.

	•		A reduction in the current deferred energy balance of $45 million leaving a balance payable to customers of approximately $29.6 million.

	•		A two-year amortization of the amount payable returning one third of the balance in the first year (approximately $9.9 million), and two thirds of the balance the second year (approximately $19.7 million).

	•		Discontinue carrying charges on deferred energy balances that SPPC is already collecting from customers and on the $29.6 million amount payable as a result of the agreement.

	•		Maintain the currently effective Base Tariff Energy Rate.

	•		SPPC maintains the rights to claim the cost of terminated energy contracts in future deferred filings.

	•		Parties agreed that with the $45 million reduction the remaining costs for purchasing fuel and power during the test year were prudently incurred and are just and reasonable.

	•		SPPC and the BCP agreed to file a motion to dismiss the civil lawsuits filed in relation to the 2001 SPPC deferred energy case.

	(1)		a requirement to pay the judgment entered by the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron for payments allegedly due under terminated purchase power contracts, or to provide additional cash collateral for the judgment pending appeal;

	(2)		unfavorable rulings in rate cases to be filed by NPC and SPPC (the Utilities) with the Public Utilities Commission of Nevada (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;

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

	(4)		whether NPC’s ability to pay SPR dividends will be restored in the near future, and whether SPPC will be able to continue to pay SPR dividends under the terms of SPPC’s financing agreements and/or restated articles of incorporation;

	(5)		whether suppliers, other than Enron, which have terminated their power supply contracts with NPC and/or SPPC will be successful in pursuing their claims against the Utilities for liquidated damages under their power supply contracts;

	(6)		whether the PUCN will issue favorable orders in a timely manner to permit the Utilities to borrow money and issue additional securities to finance the Utilities’ operations, and to purchase power and fuel necessary to serve their respective customers, and to repay maturing debt;

	(7)		whether SPR, NPC, and SPPC will be able to maintain sufficient stability with respect to their liquidity and relationships with suppliers to be able to continue to operate outside of bankruptcy;

	(8)		whether current suppliers of purchased power, natural gas, or fuel to NPC or SPPC will continue to do business with NPC or SPPC or will terminate their contracts, particularly in the event of a ratings downgrade and whether NPC or SPPC will have sufficient liquidity to pay its respective power requirements if their current suppliers continue to require the Utilities to make pre-payments or more frequent payments on their power purchases;

	(9)		whether the Utilities will need to purchase additional power on the spot market to meet unanticipated power demands (for example, due to unseasonably hot weather) and whether suppliers will be willing to sell such power to the Utilities in light of their weakened financial condition;

	(10)		whether SPPC will be successful in obtaining PUCN approval to recover the costs of the gasifier facility at the Piñon Pine Power Project in a future general rate case;

	(11)		whether NPC and SPPC will be successful in obtaining PUCN approval to recover goodwill and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

	(12)		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;

	(13)		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;

	(14)		whether the Utilities will be able, either through appeals of the Federal Energy Regulatory Commission (FERC) proceedings or negotiation, to obtain lower prices on the long-term purchased power contracts that they entered into during 2000 and 2001 that are priced above current market prices for electricity;

	(15)		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;

	(16)		unseasonable weather and other natural phenomena which, in addition to impacting 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;

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

	(18)		the loss of any significant customers;

	(19)		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;

	(20)		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;

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

	(22)		future economic conditions, including inflation or deflation rates and monetary policy;

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

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

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

	•		an unrealized gain of $61.5 million on the derivative instrument associated with the issuance of $300 million of convertible debt (see Critical Accounting Policies). This unrealized gain has no effect on cash flows;

	•		other operating expenses that included increased reserves for uncollectible accounts and costs associated with collections for NPC and SPPC (see Other Income/(Expense analysis);

	•		interest costs at SPR, NPC, and SPPC that included the recognition of $40.2 million in interest as a result of a judgment issued September 26, 2003, by the Enron Bankruptcy Court. See Note 11, Commitments and Contingencies, of the Consolidated Financial Statements for more information regarding the Enron litigation.

	•		an unrealized loss of $46.1 million on the derivative instrument associated with the issuance of $300 million of convertible debt. This unrealized loss has no effect on cash flows;

	•		the write-off of disallowed deferred energy costs (excluding carrying charges) of approximately $46 million and $45 million by NPC and SPPC, respectively;

	•		losses by SPR subsidiaries due to the recognition of asset impairments and business disposals of $32.9 million and $9.6 million by SPC and e ·three, respectively;

	•		other operating expenses that included increased reserves for uncollectible accounts and costs associated with collections for NPC and SPPC (see Other Income/(Expense analysis); and

	•		interest costs at SPR, NPC, and SPPC, including $40.2 million as a result of the Enron Bankruptcy Court judgment.

	•		NPC’s first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC’s common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $220 million as of September 30, 2003), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. Management is currently in the process of seeking consent for the modification of this restriction. There can be no assurance that any such consent can be obtained or that any non-consenting first mortgage bonds could be redeemed or defeased prior to their stated maturity. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock, although other restrictions set forth below would limit the amount of any such repurchases or redemptions.

	•		NPC’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, and NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued on August 13, 2003, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s Premium Income Equity Securities (PIES)) provided that:

	•		On October 29, 2002, NPC established an accounts receivables purchase facility, which was renewed on October 28, 2003, and will expire on October 26, 2004. The agreements relating to the receivables purchase facility contain various covenants, including a limitation on payments in respect of common stock by NPC to SPR that is identical to the limitation contained in NPC’s General and Refunding Mortgage Notes, Series E & Series G, described above.

	•		The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC’s request for authority to issue Long-Term Debt. The PUCN order requires that, until such time as the order’s authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any

			dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of September 30, 2003, NPC’s equity ratio was 36.66%. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction.

	•		The terms of NPC’s preferred trust securities provide that no dividends may be paid on NPC’s common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures.

	•		SPPC’s Term Loan Agreement dated October 30, 2002, as amended, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $90 million, $80 million, and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004, and 2005, respectively. The Term Loan Agreement also permits SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of:


	•		On October 29, 2002, SPPC established an accounts receivables purchase facility, which was renewed on October 28, 2003, and expires on October 26, 2004. The agreements relating to the receivables purchase facility contain various covenants, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC’s Term Loan Agreement, described above.

	•		SPPC’s Articles of Incorporation contain restrictions on the payment of dividends on SPPC’s common stock in the event of a default in the payment of dividends on SPPC’s preferred stock. SPPC’s Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption, or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock.

	•		The Utilities are subject to the provision of the Federal Power Act that states that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction would not be construed or applied to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts.

	•		On November 6, 2003, the Bankruptcy Court issued an order staying execution pending appeal of the September 26, 2003 judgment entered in favor of Enron against the Utilities. One of the conditions of the stay order is that the Utilities cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations. The Utilities have the right to seek modification of the conditions of the stay if there is a material change in the facts upon which the stay order is based.

	•		The indenture pursuant to which SPR issued its 7.25% Convertible Notes due 2010 provides for an event of default if SPR or any of its significant subsidiaries (NPC and SPPC) fails to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable;

	•		NPC’s General and Refunding Mortgage Indenture, under which NPC has $1.08 billion of securities outstanding as of September 30, 2003, provides for an event of default if a matured event of default under NPC’s First Mortgage Indenture occurs;

	•		The terms of NPC’s Series E Notes and NPC’s Series G Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of each series of Notes to require NPC to redeem their series of Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding noteholders for such series of Notes;

	•		NPC’s receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively;

	•		NPC’s Senior Unsecured Note Indenture, pursuant to which NPC issued its $130 million 6.20% Senior Unsecured Notes, Series B, due April 15, 2004, provides for a default if (a) NPC fails to pay indebtedness (after any applicable grace period), or (b) any of NPC’s indebtedness is accelerated, and (c) such indebtedness aggregates $15 million, and (d) such indebtedness is not repaid and such acceleration is not rescinded within 30 days;

	•		SPPC’s General and Refunding Mortgage Indenture, under which SPPC has $499.3 million of securities outstanding as of September 30, 2003, provides for an event of default if a matured event of default under SPPC’s First Mortgage Indenture occurs;

	•		SPPC’s Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC’s General and Refunding Mortgage Indenture ceases to be enforceable; and

	•		Approval of NPC’s electric load forecast as being a fair representation of expected loads during the 20-year period spanning 2003 through 2022.

	•		Approval of NPC’s fuels price forecasts as being a fair representation of expected range of prices during the same 2003 through 2022 period.

	•		Approval of NPC’s plan to reserve up to 650 MW of additional native load transmission rights on the Centennial Transmission Project following the construction of the Harry Allen-to-Mead 500 kV transmission line, the third phase of the project.

	•		Approval for re-conductoring the 230 kV Mead system that would increase system import by 450 MW at an estimated cost of $24 million.

	•		Approval to construct a combustion turbine generating plant at the Harry Allen power plant site prior to the summer peak of 2006 at an estimated cost of $44.1 million.

	•		Approval to construct a combined cycle generating plant including duct burners rated at 520 MW. The unit is planned for the Harry Allen power plant site with an in-service date prior to the 2007 summer peak, at a cost of $414.7 million.

	•		NPC will submit long-term transmission service requests to other transmission owners for capacity from the Palo Verde region to Mead. Long-term transmission capacity has been unavailable from the Palo Verde region to Mead. These requests will likely result in system impact and facility studies by these transmission owners. NPC is requesting PUCN approval of the estimated $100,000 for the aforementioned studies.

	•		Approval to spend $9.2 million, $9.3 million, and $9.3 million for calendar years 2004, 2005, and 2006, respectively, devoted to demand-side programs. The programs were developed in a collaborative effort, based upon input from various interested parties.

	•		Approval of the recommended natural gas hedging strategy for 2004.

	•		Exemption from the avoided cost filing requirements set forth in Nevada Administrative Code section 704.8783 based upon the use of a competitive bidding process to fill mega watts available to Qualifying Facilities as a result of the renewable energy request for proposal (RFP) and long-term purchase obligation RFP for up to 2,500 MW.

	•		Approval for a plant life assessment of NPC’s existing power plants, at a cost of $500,000 per each year of the Three-Year Action Plan.

			In addition, the Action Plan includes the following action items:

	•		Issue an RFP for long-term purchase power contracts to fill a substantial portion of remaining capacity requirements expected for 2004-2006. The results of the RFP and any executed contracts will be filed with the PUCN for approval.

	•		Issue an RFP to meet the Renewable Energy Portfolio Standard through 2007 as adopted and passed into law by the Nevada State Legislature. NPC proposes to execute the agreements and bring the signed agreements to the PUCN for approval as a compliance item to this plan.