Nv Energy 8K Other events

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of Earliest Event Reported) November 25, 2003


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

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

None

(Former name, former address and former fiscal year, if changed since last report)

TABLE OF CONTENTS


	Item 5. Other Events
	Item 7. Financial Statements and Exhibits
SELECTED FINANCIAL DATA
INDEPENDENT AUDITORS’ REPORT
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FINANCIAL STATEMENT SCHEDULE
SIGNATURE
EXHIBIT INDEX
EX-12.1 RATIO OF EARNINGS TO FIXED CHARGES
EX-23.1 CONSENT OF DELOITTE & TOUCHE LLP

Item 5. Other Events

Sierra Pacific Resources (“SPR”) filed a Registration Statement on Form S-3, File No. 333- 105070, as amended by Pre-Effective Amendment on Form S-3/A, which was declared effective by the Securities and Exchange Commission on August 13, 2003 (the “Registration Statement”), to register SPR’s 7.25% Convertible Notes due 2010 (the “Convertible Notes”). In accordance with its continuing registration obligations to the holders of its Convertible Notes, SPR will be filing a Post-Effective Amendment No. 1 on Form S-3/A. In connection with the filing of that Post-Effective Amendment, SPR is filing this report on Form 8-K (the “Report”) to revise information that was previously reported in its Form 10-K for the year ended December 31, 2002 to reflect discontinued operations that have been discontinued since the time of the filing of SPR’s most recent Form 10-K. These discontinued operations have been previously disclosed in SPR’s reports filed under the Securities Exchange Act of 1934.

This Report is limited to the revisions to reflect certain businesses as discontinued operations. No attempt has been made in this Report to modify or update other disclosures as presented in the original Form 10-K except as required to reflect the effects of the item described below.

In the second quarter of 2003, SPR began negotiations to sell two of its subsidiaries, e·three and e·three Custom Energy Solutions, LLC (CES). Accordingly, at June 30, 2003, SPR reported e·three and CES as discontinued operations in its From 10-Q for the quarter ended June 30, 2003. Based on the expected selling price, SPR recognized a pre-tax loss of $8.9 million on the disposal of these operations for the six months ended June 30, 2003. SPR completed the sale of e·three and CES on September 26, 2003. As a result of the final sales price, SPR recognized an additional pre-tax loss for the disposal of the businesses of $703,787 for the three months ended September 30, 2003 as reported in SPR’s Form 10-Q for the quarter ended September 30, 2003.

SPR is filing the selected financial data for the five years ended December 31, 2002, consolidated financial statements as of December 31, 2002 and 2001 and for the three years ended December 31, 2002, the consolidated valuation and qualifying accounts and ratios of earnings to fixed charges in order to report the impact of our classification of e·three and CES during the three months ended June 30, 2003, as discontinued operations pursuant to Statement of Financial Accounting Standards No. 144 – Accounting for the Impairment or Disposal of Long Lived Assets (“SFAS No. 144”). Certain reclassifications of amounts reported in prior years have been made for comparative purposes but do not affect previously reported net income or shareholders’ equity.

Item 7. Financial Statements and Exhibits

	(a)		Financial Statements of Businesses Acquired

			Not required

	(b)		Pro forma financial information

			Not required

	(c)		Exhibits
			12.1 Ratios of Earnings to Fixed Charges 23.1 Independent Auditors’ Consent

Sierra Pacific Resources

Current Report on Form 8-K
November 25, 2003

Table of Contents


SELECTED FINANCIAL DATA			5
INDEPENDENT AUDITORS’ REPORT			6
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			7
FINANCIAL STATEMENT SCHEDULE			71
SIGNATURE			72
EXHIBIT INDEX			73

SELECTED FINANCIAL DATA

SIERRA PACIFIC RESOURCES

The July 28, 1999 merger between SPR and NPC was treated for accounting purposes as a reverse acquisition and deemed to have occurred on August 1, 1999. As a result, for financial reporting and accounting purposes, NPC was considered the acquiring entity under Accounting Principles Board Opinion No. 16,Business Combinations, even though SPR became the legal parent of NPC. Because of this accounting treatment, for the year ended December 31, 1999, the table below reflects twelve months of information for NPC and five months of information for SPR and its pre-merger subsidiaries, and for the year ended December 31, 1998, reflects information for NPC only.


	Year ended December 31,
	(dollars in thousands, except per share amounts)

	2002			2001		2000			1999		1998

Operating Revenues	$	2,985,304		$	4,575,261	$	2,325,111		$	1,279,065	$	873,682

Operating Income (Loss)	$	(32,049	)	$	221,723	$	125,685		$	162,333	$	147,277

Net Income (Loss) from Continuing Operations	$	(300,851	)	$	32,898	$	(46,253	)	$	50,029	$	83,673

Earnings (Deficit) from Continuing Operations Per Average Common Share - Basic	$	(2.95	)	$	0.38	$	(0.59	)	$	0.80	$	1.64

Earnings (Deficit) from Continuing Operations Per Average Common Share - Diluted	$	(2.95	)	$	0.38	$	(0.59	)	$	0.80	$	1.64

Total Assets	$	6,896,975		$	7,992,278	$	5,677,908		$	5,235,917	$	2,541,840

Long-Term Debt and NPC Obligated Mandatorily Redeemable Preferred Trust Securities	$	3,251,755		$	3,564,909	$	2,370,971		$	1,793,919	$	1,089,099

Dividends Declared Per Common Share	$	0.20		$	0.40	$	1.00		$	1.17	$	1.45

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholders of
Sierra Pacific Resources
Reno, Nevada

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Sierra Pacific Resources and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Resources and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 20 to the consolidated financial statements, during 2002 the Company changed its method of accounting for goodwill to conform to Statement of Accounting Standards No. 142, Accounting for Goodwill.

Deloitte & Touche LLP

Reno, Nevada
February 28, 2003
(November 21, 2003 as to the discontinued operations presentation of e.three and CES described in Note 16)

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


			December 31,
			2002		2001

ASSETS
Utility Plant at Original Cost:
	Plant in service		$	5,989,701	$	5,744,041
		Less accumulated provision for depreciation		1,944,351		1,783,773

				4,045,350		3,960,268
	Construction work-in-progress			263,346		203,456

				4,308,696		4,163,724

Investments in subsidiaries and other property, net				124,580		63,297

Current Assets:
	Cash and cash equivalents			192,064		98,583
	Restricted cash (Note 1)			13,705		—
	Accounts receivable less provision for uncollectible accounts: 2002-$44,184 ; 2001-$39,335			358,972		391,867
	Deferred energy costs - electric			268,979		333,062
	Deferred energy costs - gas			17,045		19,805
	Income tax receivable			—		185,011
	Materials, supplies and fuel, at average cost			87,348		93,796
	Risk management assets (Note 19)			29,570		286,509
	Other			48,898		13,844

				1,016,581		1,422,477

Deferred Charges and Other Assets:
	Goodwill (Note 20)			309,971		311,182
	Deferred energy costs - electric			685,875		854,778
	Deferred energy costs - gas			—		23,248
	Regulatory tax asset			163,889		169,738
	Other regulatory assets (Note 1)			136,933		96,725
	Risk management assets (Note 19)			368		61,058
	Risk management regulatory assets - net (Note 19)			44,970		664,383
	Other			92,250		145,991

				1,434,256		2,327,103

Assets of Discontinued Operations (Note 16)				12,862		15,677

			$	6,896,975	$	7,992,278

CAPITALIZATION AND LIABILITIES
Capitalization:
	Common shareholders’ equity		$	1,327,166	$	1,695,336
	Preferred stock			50,000		50,000
	NPC obligated mandatorily redeemable preferred trust securities			188,872		188,872
	Long-term debt			3,062,883		3,376,037

				4,628,921		5,310,245

Current Liabilities:
	Short-term borrowings			—		177,000
	Current maturities of long-term debt			672,895		122,010
	Accounts payable			232,424		261,730
	Accrued interest			50,308		37,565
	Dividends declared			1,045		1,045
	Accrued salaries and benefits			20,798		30,145
	Deferred taxes			123,507		145,903
	Risk management liabilities (Note 19)			69,953		855,301
	Other current liabilities			46,719		15,789

				1,217,649		1,646,488

Commitments & Contingencies (Note 17)
Deferred Credits and Other Liabilities:
	Deferred federal income taxes			336,875		508,420
	Deferred investment tax credit			48,492		51,947
	Regulatory tax liability			42,718		46,702
	Customer advances for construction			116,032		108,179
	Accrued retirement benefits			107,580		82,624
	Risk management liabilities (Note 19)			3,917		163,636
	Contract termination reserves (Note 17)			312,594		—
	Other			81,410		70,420

				1,049,618		1,031,928

Liabilities of Discontinued Operations (Note 16)				787		3,617

			$	6,896,975	$	7,992,278

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

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


			Year ended December 31,
			2002			2001			2000

OPERATING REVENUES:
	Electric		$	2,832,285		$	4,426,881		$	2,221,111
	Gas			149,783			145,652			100,803
	Other			3,236			2,728			3,197

				2,985,304			4,575,261			2,325,111

OPERATING EXPENSES:
	Operation:
		Purchased power		1,786,823			4,052,077			1,116,375
		Fuel for power generation		453,436			728,619			526,535
		Gas purchased for resale		91,961			136,534			83,199
		Deferred energy costs disallowed		491,081			—			—
		Deferral of energy costs - electric - net		(233,814	)		(1,136,148	)		16,719
		Deferral of energy costs - gas - net		24,785			(23,170	)		(16,164	)
		Other		287,422			319,107			251,272
	Maintenance			64,440			69,499			52,477
	Depreciation and amortization			174,726			165,808			158,037
	Taxes:			—			—			—
		Income taxes		(167,935	)		(1,764	)		(31,238	)
		Other than income		44,428			42,976			42,214

				3,017,353			4,353,538			2,199,426

OPERATING INCOME (LOSS)				(32,049	)		221,723			125,685

OTHER INCOME (EXPENSE):
	Allowance for other funds used during construction			(36	)		474			2,813
	Interest accrued on deferred energy			23,058			55,204			205
	Other income			10,519			11,981			12,082
	Other expense			(18,373	)		(13,634	)		(8,135	)
	Income taxes			(4,058	)		(14,870	)		(511	)

				11,110			39,155			6,454

Total Income (Loss) Before Interest Charges				(20,939	)		260,878			132,139

INTEREST CHARGES:
	Long-term debt			234,532			188,119			134,536
	Other			35,478			23,892			35,576
	Allowance for borrowed funds used during construction and capitalized interest			(5,270	)		(2,801	)		(10,634	)
				264,740			209,210			159,478

	Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities			15,172			18,770			18,914

INCOME (LOSS) FROM CONTINUING OPERATIONS				(300,851	)		32,898			(46,253	)

DISCONTINUED OPERATIONS:
	Income (losses) from operations of discontinued businesses (net of income taxes of $(563), $1,422 and $3,642, respectively)			(1,204	)		1,690			9,972
	Gain on disposal of water business (net of income taxes of $18,237)			—			25,845			—

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, net of tax (Note 20)				(1,566	)		—			—

NET INCOME (LOSS)				(303,621	)		60,433			(36,281	)

Preferred stock dividend requirements of subsidiary				3,900			3,700			3,499

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK			$	(307,521	)	$	56,733		$	(39,780	)

Amount per share - basic and diluted
		Income / (Loss) from continuing operations	$	(2.95	)	$	0.38		$	(0.59	)
		Income / (Loss) per share applicable to common stock	$	(3.01	)		0.65			(0.51	)
Weighted Average Shares of Common Stock Outstanding				102,126,079			87,542,441			78,435,405

Dividends Paid Per Share of Common Stock			$	0.20		$	0.65		$	1.00

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


			Year ended December 31,

			2002			2001			2000

NET INCOME (LOSS)			$	(303,621	)	$	60,433		$	(36,281	)
OTHER COMPREHENSIVE INCOME (LOSS)
	Adoption of SFAS No. 133- Accounting for Derivative Instruments and Hedging Activities:
		Cummulative effect upon adoption of change in accounting principle as of January 1 (Net of taxes of $1,035)		—			(1,923	)		—
		Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $3,083 and $2,726 in 2002 and 2001, respectively)		5,726			(5,063	)		—
	Minimum pension liability adjustment (Net of taxes of $24,904)			(46,251	)		—			—

OTHER COMPREHENSIVE (LOSS)				(40,525	)		(6,986	)		—

COMPREHENSIVE INCOME (LOSS)			$	(344,146	)	$	53,447		$	(36,281	)

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)

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			Year ended December 31,

			2002			2001			2000

Common Stock:
Balance at Beginning of Year			$	102,111		$	78,475		$	78,414
	Stock purchase and dividend reinvestment			66			23,636			61

Balance at end of year				102,177			102,111			78,475

Other Paid-In Capital:
Balance at Beginning of Year				1,598,634			1,295,221			1,293,990
	Premium on sale of common stock			—			330,050			—
	Common Stock issuance costs			—			(13,910	)		—
	Purchase contract adjustment payment			—			(13,676	)		—
	CSIP, DRP, ESPP and other			390			949			1,231

Balance at End of Year				1,599,024			1,598,634			1,295,221

Retained Earnings (Accumulated Deficit):
Balance at Beginning of Year				1,577			(13,984	)		104,725
	Income (loss) from continuing operations			(300,851	)		32,898			(46,253	)
	Income (loss) from discontinued operations (before preferred dividend allocation of $200 and $401 in 2001 and 2000, respectively)			(1,204	)		1,890			10,373
	Cumulative effect of change in accounting principle, net of tax			(1,566	)		—			—
	Gain on disposal of water business			—			25,845			—
	Preferred stock dividends declared			(3,900	)		(3,900	)		(3,900	)
	Common stock dividends declared			(20,580	)		(41,172	)		(78,929	)

Balance at End of Year				(326,524	)		1,577			(13,984	)

Accumulated Other Comprehensive Income (Loss):
Balance at Beginning of Year				(6,986	)		—			—
		Cumulative effect upon adoption of change in accounting principle as of January 1 (net of taxes of $1,035)		—			(1,923	)		—
		Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $3,083 and $2,726 in 2002 and 2001, respectively)		5,726			(5,063	)		—
	Minimum pension liability adjustment (net of taxes of $24,904)			(46,251	)		—			—

Balance at End of Year				(47,511	)		(6,986	)		—

Total Common Shareholders’ Equity at End of Year			$	1,327,166		$	1,695,336		$	1,359,712

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

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

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				Year ended December 31,

				2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net Income (Loss)			$	(303,621	)	$	60,433		$	(36,281	)
	Preferred dividends included in discontinued operations							200			401
	Non-cash items included in income:
		Depreciation and amortization			175,218			169,289			164,858
		Deferred taxes and deferred investment tax credit			(17,770	)		85,917			(18,564	)
		AFUDC and capitalized interest			(5,234	)		(3,285	)		(13,858	)
		Amortization of deferred energy costs - electric			176,718
		Amortization of deferred energy costs - gas			13,231			3,562
		Deferred energy costs disallowed (net of taxes)			320,484
		Early retirement and severance amortization			2,706			3,121			4,196
		Gain on disposal of water business						(44,081	)
		Other non-cash			5,818			2,862			31,550
		Adjustment in value of Premium Income Equity Securities						(13,677	)
	Changes in certain assets and liabilities:
		Accounts receivable			32,896			(887	)		(174,120	)
		Deferral of energy costs - electric			(413,654	)		(1,187,840	)		14,884
		Deferral of energy costs - gas			10,270			(30,245	)		(16,370	)
		Materials, supplies and fuel			6,448			(18,328	)		(1,580	)
		Other current assets			(48,760	)		4,454			(52,118	)
		Accounts payable			(29,307	)		(97,340	)		221,038
		Income tax receivable			185,011
		Other current liabilities			34,322			13,025			19,129
		Change in net assets of discontinued operations			535			(10,893	)		(8,034	)
		Other assets			(3,073	)		(9,331	)		9,971
		Other liabilities			316,562			19,200			34,184

Net Cash from Operating Activities					458,800			(1,053,844	)		179,286

CASH FLOWS FROM INVESTING ACTIVITIES:
		Additions to utility plant			(399,807	)		(333,606	)		(360,130	)
		AFUDC and other charges to utility plant			5,234			3,285			15,227
		Customer advances (refunds) for construction			7,852			815			(889	)
		Contributions in aid of construction			43,247			27,481			16,446

		Net cash used for utility plant			(343,474	)		(302,025	)		(329,346	)
		Proceeds from sale of assets of water business			—			318,882			—
		Investments in subsidiaries and other property - net			(57,755	)		(9,065	)		(21,090	)

Net Cash from Investing Activities					(401,229	)		7,792			(350,436	)

CASH FLOWS FROM FINANCING ACTIVITIES:
		Decrease in short-term borrowings			(177,000	)		(36,074	)		(547,310	)
		Proceeds from issuance of long-term debt			350,000			1,225,503			1,165,000
		Retirement of long-term debt			(112,269	)		(323,091	)		(318,061	)
		Redemption of preferred stock			—			(48,500	)		—
		Sale of common stock			460			340,737			1,292
		Dividends paid			(24,485	)		(64,917	)		(83,057	)

Net Cash from Financing Activities					36,706			1,093,658			217,864

Net Increase in Cash and Cash Equivalents					94,277			47,606			46,714
Beginning Balance in Cash and Cash Equivalents					99,109			51,503			4,789

Ending Balance in Cash and Cash Equivalents				$	193,386		$	99,109		$	51,503

Supplemental Disclosures of Cash Flow Information:
		Cash paid (received) during period for:
			Interest	$	257,452		$	208,390		$	167,158
			Income taxes	$	(185,011	)	$	(55,022	)	$	12,730

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)

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				December 31,

				2002			2001

Common Shareholders’ Equity:
	Common stock $1.00 par value, authorized 250 million shares; issued and outstanding 2002: 102,177,000 shares; 2001, 102,111,000 shares			$	102,177		$	102,111
	Other paid-in capital				1,599,024			1,598,634
	Retained earnings accumulated (deficit)				(326,524	)		1,577
	Accumulated Other Comprehensive Loss				(47,511	)		(6,986	)

		Total Common Shareholders’ Equity			1,327,166			1,695,336

Preferred Stock of Subsidiaries:
Not subject to mandatory redemption
Outstanding at December 31
	Class A Series 1; $1.95 dividend				50,000			50,000

Preferred Trust Securities of Subsidiaries:
Obligated Mandatorily Redeemable Preferred Securities of NPC’s Subsidiary Trust, NVP Capital I, holding solely $122.6 million principal amount of 8.2% Junior Subordinated Debentures of NPC, due 2037					118,872			118,872
Obligated Mandatorily Redeemable Preferred Securities of NPC’s Subsidiary Trust, NVP Capital III, holding solely $72.2 million principal amount of 7.75% Junior Subordinated Debentures of NPC, due 2038					70,000			70,000

			Total Preferred Securities of Subsidiaries		188,872			188,872

Long-Term Debt:
Unamortized bond premium and discount, net					(17,968	)		(959	)
Debt Secured by First Mortgage Bonds
		7.63% Series L due 2002			—			15,000
		6.70% Series V due 2022			105,000			105,000
		6.60%Series W due 2019			39,500			39,500
		7.20% Series X due 2022			78,000			78,000
		8.50% Series Z due 2023			35,000			35,000
		2.00% Series Z due 2004			—			56
		2.00% Series O due 2011			—			1,281
		6.35% Series FF due 2012			1,000			1,000
		6.55% Series AA due 2013			39,500			39,500
		6.30% Series DD due 2014			45,000			45,000
		6.65% Series HH due 2017			75,000			75,000
		6.65% Series BB due 2017			17,500			17,500
		6.55% Series GG due 2020			20,000			20,000
		6.30% Series EE due 2022			10,250			10,250
		6.95% to 8.61% Series A MTN due 2022			110,000			110,000
		7.10% and 7.14% Series B MTNdue 2023			58,000			58,000
		6.62% to 6.83% Series C MTN due 2006			50,000			50,000
		5.90% Series JJ due 2023			9,800			9,800
		5.90% Series KK due 2023			30,000			30,000
		5.00% Series Y due 2024			—			3,072
		6.70% Series II due 2032			21,200			21,200
		5.50% Series D MTN due 2003			5,000			5,000
		5.59% Series D MTN due 2003			13,000			13,000

			Subtotal		744,782			781,200

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)

Continued from previous page


			December 31,

			2002			2001

Industrial development revenue bonds
	5.90% Series 1997A due 2032			52,285			52,285
	5.90% Series 1995B due 2030			85,000			85,000
	5.60% Series 1995A due 2030			76,750			76,750
	5.50% Series 1995C due 2030			44,000			44,000
	6.20% Series 1999B due 2004			130,000			130,000

		Subtotal		388,035			388,035

Pollution control revenue bonds
	6.38% due 2036			20,000			20,000
	5.80% Series 1997B due 2032			20,000			20,000
	5.30% Series 1995D due 2011			14,000			14,000
	5.45% Series 1995D due 2023			6,300			6,300
	5.35% Series 1995E due 2022			13,000			13,000

		Subtotal		73,300			73,300

Variable Rate Notes
	Floating rate notes due 2003			140,000			140,000
	IDRB Series 2000A due 2020			100,000			100,000
	PCRB Series 2000B due 2009			15,000			15,000
	Floating Rate Notes due 2002			—			100,000
	Floating Rate Notes due 2003			200,000			200,000

		Subtotal		455,000			555,000

Debt Secured by General and Refunding Bonds:
	8.25% Series A due 2011			350,000			350,000
	10.88% Series E due 2009			250,000			—
	8.00% Series A due 2008			320,000			320,000
	10.50% (Variable) Series C due 2005			100,000			—

		Subtotal		1,020,000			670,000

Other Notes:
	5.75% Series 2001 due 2036			80,000			80,000
	6.00% Series B notes due 2003			210,000			210,000
	8.75% Senior unsecured note Series 2000 due 2005			300,000			300,000
	7.93% Senior unsecured notes due 2007			345,000			345,000

		Subtotal		935,000			935,000

Obligations under capital leases				73,259			78,313

Current maturities and sinking fund requirements				(672,895	)		(122,010	)

Other				46,402			17,199

		Total Long-Term Debt		3,062,883			3,376,037

TOTAL CAPITALIZATION			$	4,628,921		$	5,310,245

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

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

General

The consolidated financial statements include the accounts of Sierra Pacific Resources (SPR) and its wholly-owned subsidiaries, Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Lands of Sierra, Inc. (LOS), Sierra Energy Company dba e·three (e·three), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and, Sierra Gas Holding Company (SGHC). e·three is a discontinued operation and as such is reported separately in the financial statements. NPC and SPPC are referred to together in this report as the Utilities. All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 59% of the consolidated assets of SPR at December 31, 2002. NPC provides electricity to approximately 669,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. Service is also provided to the Department of Energy’s Nevada Test Site in Nye County. The consolidated financial statements of SPR include the accounts of NPC’s wholly owned subsidiaries, Nevada Electric Investment Company (NEICO), NVP Capital I, and NVP Capital III.

SPPC is an operating public utility that provides electric service in northern Nevada and northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada. The assets of SPPC represent approximately 35% of the consolidated assets of SPR at December 31, 2002. SPPC provides electricity to approximately 318,000 customers in a 50,000 square mile service area including western, central, and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. The consolidated financial statements of SPR include the accounts of SPPC’s wholly owned subsidiaries, Piñon Pine Corporation, Piñon Pine Investment Company, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I.

The Utilities’ accounts for electric operations and SPPC’s accounts for gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC).

TGPC is a partner in a joint venture that developed, constructed, and operates a natural gas pipeline serving the expanding gas market in the Reno area and certain northeastern California markets. TGPC accounts for its joint venture interest under the equity method. e·three provides comprehensive energy services in commercial and industrial markets on a regional basis. SPE markets a package of telecommunication products and services. SPC was formed in 1999 to provide telecommunications services using fiber optic cable technology in both northern and southern Nevada.

Certain reclassifications of prior year information have been made for comparative purposes but have not affected previously reported net income or common shareholders’ equity.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect

the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

Management’s Statement

Sierra Pacific Resources

SPR, on a stand-alone basis, had cash and cash equivalents of approximately $7.4 million at December 31, 2002, and approximately $179.3 million at February 28, 2003.

Currently, SPR has a substantial amount of debt and other obligations including, but not limited to: $133 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8¾% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. SPR intends to pay off the remaining principal balance of its Floating Rate Notes due April 20, 2003 with cash currently on hand.

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 a restoration of its ability to pay dividends to SPR, and on SPR’s ability to access the capital markets or otherwise refinance maturing debt. On October 29, 2002, SPPC paid a common stock dividend of $25 million to its parent, SPR. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult to continue to operate outside of bankruptcy.

See Note 13, Dividend Restrictions for information regarding the dividend restrictions applicable to NPC and SPPC and Note 17, Commitments and Contingencies for additional information regarding uncertainties that could impact the SPR’s liquidity and financial condition.

The provisions that currently restrict dividends payable 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 intends to seek a modification of the financial covenant contained in NPC’s first mortgage indenture in the near future. The regulatory limitation contained in the PUCN’s Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. 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.

Financing Transactions. 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 have been 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 will be used to repay the remainder of SPR’s Floating Rate Notes due April 20, 2003 at maturity, and the remaining approximately $65 million will be available for general corporate purposes, including the payment of interest on SPR’s other outstanding indebtedness.

the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the average closing price of SPR’s common stock over five consecutive trading days for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.20 (the last reported sale price of SPR’s common stock on March 17, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $137 million. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt.

If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, for approval to issue and deliver shares of SPR’s common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. For further information regarding the terms of the Convertible Notes, see Note 9, Long-Term Debt.

Effect of Holding Company Structure. Due to the holding company structure, SPR’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, SPR’s debt obligations are effectively subordinated to all existing and future claims of its subsidiaries’ creditors, particularly those of NPC and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders and NPC’s and SPPC’s preferred security holders. As of December 31, 2002, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. 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.

The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above.

Nevada Power Company

NPC had cash and cash equivalents of approximately $95 million at December 31, 2002, and approximately $96 million at February 28, 2003.

In addition to anticipated capital requirements for construction, NPC has approximately $355 million of debt maturing in 2003. NPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt.

NPC’s liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. S&P and Moody’s have NPC’s credit ratings on “negative” and “stable”, respectively. Future downgrades by either S&P or Moody’s could preclude NPC’s access to the capital markets. Furthermore, if NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC

under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC’s business, operations and financial condition will be adversely affected. Adverse developments with respect to any one or a combination of the foregoing could make it difficult to continue to operate outside of bankruptcy.

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 December 31, 2002, $870 million of NPC’s General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage Bonds, and/or (3) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert’s certificate under the General and Refunding Mortgage Indenture.

As of December 31, 2002, NPC had the capacity to issue approximately $1.04 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in NPC’s Series E Notes limit NPC’s ability to issue additional General and Refunding Mortgage Bonds or other debt. See Note 9, Long-Term Debt for information regarding NPC’s Series E Notes. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC’s receivables facility. See Note 12, Short-Term Borrowings for information regarding NPC’s accounts receivable facility. NPC intends to use its accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond.

The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above.

Sierra Pacific Power Company

SPPC had cash and cash equivalents of approximately $88.9 million at December 31, 2002, and approximately $104.2 million at February 28, 2003.

In addition to anticipated capital requirements for construction, SPPC has approximately $101 million of debt maturing in 2003. SPPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt.

SPPC’s future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody’s have SPPC’s credit ratings on “negative outlook” and “stable”, respectively. Future downgrades by either S&P or Moody’s could preclude SPPC’s access to the capital markets. Furthermore, if SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, and is unable to obtain power through other means, SPPC’s business, operations and financial condition will be adversely affected. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could make it difficult to continue to operate outside of bankruptcy.

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 December 31, 2002,

$420 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 delivery to the indenture trustee of the initial expert’s certificate under the General and Refunding Mortgage Indenture.

At December 31, 2002, SPPC had the capacity to issue approximately $427 million of additional General and Refunding Mortgage securities. However, the financial covenants contained in SPPC’s Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC’s ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. See Note 9, Long-Term Debt for information regarding SPPC’s Term Loan Agreement and Note 12, Short-Term Borrowings for information regarding SPPC’s accounts receivable facility. SPPC intends to use its 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.

The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above.

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are currently subject to the approval of the PUCN and, in the case of SPPC, rates are also subject to the approval of the 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.

In addition to the deferral of energy costs discussed below, significant items to which SPR and the Utilities apply regulatory accounting include goodwill and other merger costs resulting from the 1999 merger of SPR and NPC, generation divestiture costs, and the loss on reacquired debt.

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.

Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and the Utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to

write off their associated regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Utilities’ future financial position and results of operations.

Management periodically assesses whether the requirements for application of SFAS No. 71 are satisfied. The provisions of Assembly Bill 369 (AB 369), signed into law in April 2001, include the repeal of all statutes authorizing retail competition in Nevada’s electric utility industry. Accordingly, the Utilities continue to apply regulatory accounting to the generation, transmission and distribution portions of their businesses.

The following Other regulatory assets were included in the consolidated balance sheets of SPR as of December 31 (dollars in thousands):


		Receiving Regulatory Treatment
	Remaining					Waiting for
	Amortization	Earning a		Not Earning		Regulatory		2002		2001
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total

Early retirement and severance offers	Various thru 2004	$	—	$	4,995	$	—	$	4,995	$	7,701
Loss on reacquired debt	Term of Related Debt		31,812		—		—		31,812		32,882
Plant assets	Various thru 2031		3,558		—		—		3,558		3,783
Nevada divestiture costs			—		—		32,313		32,313		—
Merger transition costs (a)			—		—		12,601		12,601		10,543
Merger severance/relocation (a)			—		—		21,747		21,747		21,851
Merger goodwill (a)			—		—		19,675		19,675		19,675
California restructure costs			—		—		4,318		4,318		3,631
Conservation programs			—		—		3,374		3,374		1,798
Variable rate mechanism deferral			—		—		721		721		454
Other costs			—		—		1,819		1,819		(5,593	)

Total regulatory assets		$	35,370	$	4,995	$	96,568	$	136,933	$	96,725

(a)

See Note 2, Sierra Pacific Resources and Nevada Power Merger, for additional information about the accounting treatment and regulatory recovery of merger costs. Merger goodwill above represents the portion of total goodwill that has been reclassified to a regulatory asset.

Deferral of Energy Costs

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, which are described in greater detail in Note 3, Regulatory Actions, 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.

NPC utilized deferred energy accounting procedures until August 1, 2000, and resumed those procedures on March 1, 2001. SPPC resumed deferred energy accounting procedures for its natural gas operations as of January 1, 2000, and for its electric operations on March 1, 2001.

The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):


			December 31, 2002

			NPC			SPPC			SPPC			SPR
Description			Electric			Electric			Gas			Total

Unamortized balances approved for collection in current rates			$	331,159		$	120,183		$	18,957		$	470,299
Balances pending PUCN approval				195,670			15,380			—			211,050
Balances accrued since end of periods submitted for PUCN approval (1)				(17,750	)		(148	)		(1,912	)		(19,810	)
Terminated suppliers (2)				228,459			81,901			—			310,360

		Total	$	737,538		$	217,316		$	17,045		$	971,899

Current Assets
	Deferred energy costs - electric		$	213,193		$	55,786		$	—		$	268,979
	Deferred energy costs - gas			—			—			17,045			17,045
Deferred Assets
	Deferred energy costs - electric			524,345			161,530			—			685,875

		Total	$	737,538		$	217,316		$	17,045		$	971,899


			December 31, 2001

			NPC		SPPC		SPPC		SPR
Description			Electric		Electric		Gas		Total

Unamortized balances approved for collection in current rates			$	—	$	—	$	37,956	$	37,956
Balances pending PUCN approval				921,917		205,418		—		1,127,335
Balances accrued since end of periods submitted for PUCN approval				58,148		2,357		5,097		65,602

		Total	$	980,065	$	207,775	$	43,053	$	1,230,893

Current Assets
	Deferred energy costs - electric		$	281,555	$	51,507	$	—	$	333,062
	Deferred energy costs - gas			—		—		19,805		19,805
Deferred Assets
	Deferred energy costs - electric			698,510		156,268		—		854,778
	Deferred energy costs - gas			—		—		23,248		23,248

		Total	$	980,065	$	207,775	$	43,053	$	1,230,893

(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 17, Commitments and Contingencies.

Utility Plant

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. The cost of current repairs and minor replacements is charged to operating expenses when incurred.

In addition to direct labor and material costs, certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity. 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).

Allowance For Funds Used During Construction and Capitalized Interest

As part of the cost of constructing utility plant, the Utilities capitalize AFUDC. AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is capitalized in the same manner as construction labor and material costs, with an offsetting credit to “other income” for the portion representing the cost of equity funds and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NPC’s AFUDC rates used during 2002, 2001 and 2000 were 4.72%, 8.32%, and 8.34%, respectively. SPPC’s AFUDC rates used during 2002, 2001 and 2000 were 5.54%, 7.97%, and 7.17%, respectively. As specified by the PUCN, certain projects were assigned a lower AFUDC rate due to specific low-interest-rate financings directly associated with those projects.

Depreciation

Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC, which also approves any changes the Utilities may make to depreciation rates utilized for this property. Depreciation is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC’s depreciation provision for 2002, 2001 and 2000, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.0%, 2.94%, and 2.76%. SPPC’s depreciation provision for 2002, 2001 and 2000, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.33%, 3.29%, and 3.25%, respectively.

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.

Cash and Cash Equivalents

Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds.

Federal Income Taxes and Investment Tax Credits

SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiary’s respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. Deferred taxes are provided on temporary differences at the statutory income tax rate in effect as of the most recent balance sheet date.

SPR accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the difference between straight-line and accelerated tax depreciation on post-1969 utility plant expansion property, deferred energy, and certain other differences between financial reporting and taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred taxes on the benefits derived from using the Modified Accelerated Cost Recovery System.

Investment tax credits are no longer available to the Utilities. The deferred investment tax credits are being amortized over the estimated service lives of the related properties.

Revenues

Operating revenues include billed and unbilled utility revenues. The accrual for unbilled revenues represents amounts owed to the Utilities for service provided to customers for which the customers have not yet been billed. These unbilled amounts are also included in accounts receivable.

Revenues related to the sale of energy are recorded based on meter reads, which occur 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.

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 December 31, 2002, SPR had several stock-based compensation plans which are described more fully in Note 15 “Stock 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. 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 applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except per share amounts):


			2002			2001		2000

Stock Compensation Cost included in Net Income as Reported, net of related tax effects		As Reported	$	(1,567	)	$	346	$	(152	)

Earnings (Deficit) applicable to Common Stock		As Reported	$	(307,521	)	$	56,733	$	(39,780	)
	Less: Stock Compensation Cost, net of related tax effects	Pro Forma		2,047			1,209		695

Earnings (Deficit) applicable to Common Stock		Pro Forma	$	(309,568	)	$	55,524	$	(40,475	)

Basic Earnings Per Share		As Reported	$	(3.01	)	$	0.65	($	0.51	)
		Pro Forma	$	(3.03	)	$	0.63	($	0.52	)
Diluted Earnings Per Share		As Reported	$	(3.01	)	$	0.65	($	0.51	)
		Pro Forma	$	(3.03	)	$	0.63	($	0.52	)

Recent Pronouncements

See Note 20, Change in Accounting for Goodwill, for a discussion of SPR’s implementation of SFAS No. 142.

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. Management has determined that the present value of NPC’s Navajo Asset Retirement Obligation will not have a material effect on the financial position or results of operations of SPR or NPC. 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.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” This standard provides guidance on the impairment of long-lived assets and for long-lived assets to be disposed of. The standard supersedes the current authoritative literature on impairments as well as disposal of a segment of a business and was adopted January 1, 2002.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other things, this statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt” which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, the criteria in Accounting Principles Board Opinion No. 30, “Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” will now be used to classify those gains and losses. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. A fundamental conclusion reached by the FASB in this statement is that an entity’s commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC.

On January 22, 2003, the FASB directed its staff to prepare a draft of SFAS No. 149, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity.” The final draft is expected to be issued in March 2003. The statement will establish standards for accounting for financial instruments with characteristics of liabilities, equity, or both. As such, the NPC obligated mandatorily redeemable preferred trust securities may be classified as a liability once SFAS No. 149 goes into effect. The proposed effective date of SFAS No. 149 is July 1, 2003.

In November 2002, the FASB issued Interpretation 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,” 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 the Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. As of December 31, 2002, any guarantees of SPR and its subsidiaries were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries to a third party.

NOTE 2. SIERRA PACIFIC RESOURCES AND NEVADA POWER MERGER

On July 28, 1999, the merger between SPR and NPC was consummated. The merger was accounted for as a reverse purchase under generally accepted accounting principles, with NPC considered the acquiring entity even though SPR is the surviving legal entity. As a result of the acquisition, goodwill of $331.2 million was recognized which represented the total consideration paid to SPR common shareholders less the fair value of SPR’s net assets.

The order issued by the PUCN in Docket No. 98-7023 on December 31, 1998 approving the merger of SPR and NPC directed both SPPC and NPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order instructed 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. Accordingly, goodwill amortization associated with the regulated Utilities has been reclassified to a regulatory asset.

Also deferred as a result of the PUCN order is $62.2 million in other merger costs as of December 31, 2002. These deferred costs consist of $40.5 million of transaction and transition costs and $21.7 million of employee separation costs. Employee separation costs were comprised of $17.2 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains.

On October 1, 2001 and November 30, 2001, NPC and SPPC, respectively, filed applications with the PUCN for general rate increases that included, among other items, a request to recover deferred merger costs, including goodwill. The PUCN in its decisions on March 27, 2002 and May 28, 2002, for NPC and SPPC, respectively, decided not to make any determination on the recovery of merger costs until a general rate case is filed with a test year ending on or after December 31, 2002. However, the PUCN did instruct NPC and SPPC to continue to recognize these costs as deferred costs without carrying charges.

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 that are required to be filed in 2003. 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 SFAS No. 142. A significant disallowance of goodwill or merger costs by the PUCN could have a material adverse affect on the future financial condition, results of operations and cash flows of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.

NOTE 3. REGULATORY ACTIONS

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

As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, 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 quality, water pollution, solid, hazardous and toxic waste. SPR’s Board of Directors has a comprehensive environmental policy and separate board committee that oversees NPC, SPPC, and SPR’s corporate performance and achievements related to the environment.

Deferred Energy Accounting

On April 18, 2001, the Governor of Nevada signed into law AB 369. AB 369 required the Utilities to use deferred energy accounting for their respective electric operations beginning on March 1, 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel.

Nevada Power Company 2001 General Rate Case

On October 1, 2001, NPC filed an application with the PUCN, as required by law, seeking an electric general rate increase. On December 21, 2001, NPC filed a certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of $22.7 million, or an overall 1.7% rate increase. The application also sought a return on common equity (ROE) for NPC’s total electric operations of 12.25% and an overall rate of return (ROR) of 9.30%.

On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adjustments increasing accumulated depreciation by $6.7 million, and the inclusion of approximately $5 million of revenues related to SO2 Allowances. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case. NPC was not granted a carrying charge on these deferred costs. NPC plans to renew its request to recover these costs in its next general rate case, which will be filed by the fourth quarter 2003. Recovery of costs related to the generation divestiture project, which supported Nevada’s now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs.

On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. The PUCN modified its original order reversing the adjustment to accumulated depreciation of $6.7 million, and decreased the SO2 allowance revenue amortization to $3.2 million per year. Revised rates for these changes went into effect on June 1, 2002.

Nevada Power Company 2001 Deferred Energy Case

On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances 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 Deferred Energy Accounting Adjustment (DEAA) rate to clear 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 the First District Court of Nevada seeking to reverse portions of the PUCN’s decision.

Nevada Power Company 2002 Deferred Energy Case

On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay 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 requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. A hearing is scheduled to begin on April 7, 2003 and a ruling is required by May 15, 2003.

Sierra Pacific Power Company 2001 General Rate Case

On November 30, 2001, as required by law, SPPC filed an application with the PUCN seeking an electric general rate increase. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric revenues of $15.9 million representing an overall 2.4% rate increase. The application also sought an ROE for SPPC’s total electric operations of 12.25% and an overall ROR of 9.42%.

On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case, and SPPC was not granted a carrying charge on these deferred costs. SPPC is currently planning to renew its request to recover these costs in a general rate case to be filed by the fourth quarter of 2003. Recovery of costs related to the generation divestiture project, which supported Nevada’s now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs.

Sierra Pacific Power Company 2002 Deferred Energy Case

On February 1, 2002, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a DEAA 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. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs.

On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges.

On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. SPPC’s lawsuit requests 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 SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing has been scheduled for October 2003.

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 seeks to establish a DEAA 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 seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would amount to 0.01%. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003.

Annual Purchased Gas Cost Adjustment

On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application for its natural gas local distribution company. In the application, SPPC has asked for a reduction of $0.05421 to its Base Purchased Gas Rate and an increase in its Balancing Account Adjustment charge by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the Liquid Petroleum Gas Cost Adjustment below.

On December 23, 2002, the PUCN voted to decrease rates for SPPC’s natural gas customers by approximately 3% ($3.2 million plus applicable carrying charges). The PUCN noted that the decrease was due primarily to lower gas costs for SPPC and to a disallowance for imprudent hedging practices. The PUCN adjusted SPPC’s costs related to fixed floating hedging contracts. The PUCN also disallowed an alleged $0.7 million customer subsidy under an SPPC optional gas tariff. The new rates were implemented January 1, 2003.

SPPC has filed a petition for reconsideration of the decisions to disallow the $3.2 million hedging costs and the $0.7 million alleged customer subsidy. On February 6, 2003, the PUCN granted the petition for reconsideration and a decision is expected by the end of the first quarter 2003.

NOTE 4. EARNINGS PER SHARE

The following table outlines the calculation for earnings per share (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 shares and a non-employee director stock plan. Common stock equivalents were determined using the treasury stock method. Also see Note 7, Common Stock and Other Paid-in Capital.


			2002			2001		2000

Basic EPS
	Numerator ($000)
		Income (loss) from continuing operations	$	(300,851	)	$	32,898	$	(46,253	)
		Income / (loss) from discontinued operations	$	(1,204	)	$	1,690	$	9,972
		Gain on disposal of water business	$	—		$	25,845	$	—
		Cumulative effect of change in accounting principle	$	(1,566	)	$	—	$	—
		Income / (loss) applicable to common stock	$	(307,521	)	$	56,733	$	(39,780	)
	Denominator
		Weighted average number of shares outstanding		102,126,079			87,542,441		78,435,405

	Per-Share amount
		From continuing operations	$	(2.95	)	$	0.38	$	(0.59	)
		From discontinued operations	$	(0.01	)	$	0.02	$	0.13
		Gain on disposal of water business	$	—		$	0.30	$	—
		Cumulative effect of change in accounting principle	$	(0.01	)	$	—	$	—
		Income / (loss) applicable to common stock	$	(3.01	)	$	0.65	$	(0.51	)
Diluted EPS
	Numerator ($000)
		Income (loss) from continuing operations	$	(300,851	)	$	32,898	$	(46,253	)
		Income from discontinued operations	$	(1,204	)	$	1,690	$	9,972
		Gain on disposal of water business	$	—		$	25,845	$	—
		Cumulative effect of change in accounting principle	$	(1,566	)	$	—	$	—
		Income / (loss) applicable to common stock	$	(307,521	)	$	56,733	$	(39,780	)
	Denominator¹
		Weighted average number of shares outstanding before dilution		102,126,079			87,542,441		78,435,405
		Stock options		8,154			14,021		5,645
		Executive long term incentive plan - performance shares		8,918			43,693		35,393
		Non-Employee stock plan		13,861			9,355		5,885
		Employee stock purchase plan		1,163			2,862		2,807

				102,158,175			87,612,372		78,485,135

	Earnings (Deficit) Per Share²
		From continuing operations	$	(2.95	)	$	0.38	$	(0.59	)
		From discontinued operations	$	(0.01	)	$	0.02	$	0.13
		Gain on disposal of water business	$	—		$	0.30	$	—
		Cumulative effect of change in accounting principle	$	(0.01	)	$	—	$	—
		Income / (loss) applicable to common stock	$	(3.01	)	$	0.65	$	(0.51	)

¹ 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 December 31, 2002.

² Because of net losses for the years ended December 31, 2000 and 2002, stock equivalents would be anti-dilutive. Accordingly, Diluted EPS for those periods are computed using weighted average number of shares outstanding before dilution.

NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

Investments in subsidiaries and other property consisted of (dollars in thousands):

Sierra Pacific Resources


	December 31,
	2002		2001

Investment in Tuscarora Gas Transmission Company	$	26,912	$	18,799
Non-utility property of SPC and Investment in Sierra Touch America		68,353		15,340
Cash Value-Life Insurance		12,560		12,580
Non-utility property of NEICO		6,555		6,445
Other non-utility Property		10,200		10,133

	$	124,580	$	63,297

NOTE 6. JOINTLY OWNED FACILITIES

At December 31, 2002, SPR owned the following undivided interests in jointly owned electric utility facilities:


		% Owned								Construction
		by				Accumulated		Net Plant in		Work in
Generating Facility		Subsidiary		Plant in Service		Depreciation		Service		Progress		Subsidiary

Navajo Station			11.3	$	228,133	$	104,198	$	123,935	$	1,572	NPC
Mohave Facility			14.0		84,914		39,230		45,684		3,038	NPC
Reid Gardner No. 4			32.2		124,321		56,435		67,886		198	NPC
Valmy Station			50.0		282,807		133,038		149,769		—	SPPC

	TOTAL			$	720,175	$	332,901	$	387,274	$	4,808

The amounts for Navajo and Mohave include NPC’s share of transmission systems and general plant equipment and, in the case of Navajo, NPC’s share of the jointly owned railroad which delivers coal to the plant. Each participant provides its own financing for all of these jointly owned facilities. NPC’s share of operating expenses for these facilities is included in the corresponding operating expenses in its Consolidated Statements of Operations.

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.

NPC is currently evaluating and analyzing all of its options with regard to the Mohave project.

SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operator of the plant for both parties. SPPC’s share of direct operation and maintenance expenses for Valmy is included in its accompanying Consolidated Statements of Operations.

NOTE 7. COMMON STOCK AND OTHER PAID-IN CAPITAL

On September 21, 1999, the Board of Directors of SPR (the SPR Board) declared a dividend distribution of one right (an SPR Right) for each outstanding share of SPR common stock to shareholders of record at the close of business on October 31, 1999. By issuing the new SPR Rights, the SPR Board extended the benefits and protections afforded to shareholders under the Rights Agreement, dated as of October 31, 1989, which expired on October 31, 1999. Each SPR Right, initially evidenced by and traded with the shares of SPR Common Stock, entitles the registered holder (other than an “Acquiring Person” as defined in the Rights Agreement) to purchase at an exercise price of $75.00, $150.00 worth of common stock at its then-market value, subject to certain conditions and approvals set forth in the Rights Agreement. If, at any time while there is an Acquiring Person, SPR engages in a merger or other business combination transaction or series of related transactions in which the Common Stock is changed or exchanged or 50% or more of its assets or earning power is transferred, each SPR Right (not previously voided by the occurrence of a Flip-in Event, as described in the Rights Agreement) will entitle its holder to purchase, at the SPR Right’s then-current Exercise Price, common stock of such Acquiring Person having a calculated value of twice the SPR Right’s then-current Exercise Price. The SPR Rights are not exercisable until the Distribution Date and expire on October 31, 2009, unless previously redeemed by SPR. Following an SPR Distribution Date, the SPR Rights will trade separately from the SPR Common Stock and will be evidenced by separate certificates. Until an SPR Right is exercised, the holder thereof will have no rights as a shareholder of SPR, including, without limitation, the right to receive dividends. The purpose of the plan is to help ensure that SPR’s shareholders receive fair and equal treatment in the event of any proposed hostile takeover of SPR.

On August 15, 2001, SPR completed a public offering of 23,575,000 shares of its common stock, yielding net proceeds of approximately $340 million, all of which were contributed to NPC as an additional equity investment.

On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate Premium Income Equity Securities (PIES). Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50. The senior notes are pledged as collateral to secure each holder’s obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes pledged as collateral.

Each stock purchase contract obligates the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor is entitled to receive will depend on the average closing price of SPR common stock over a 20-day trading period prior to the settlement. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations.

The purchase contracts are forward transactions in SPR common stock. Upon issuance, a liability for the present value of the purchase contract adjustment payments, approximately $13.7 million, was recorded in Other deferred credits, with a corresponding reduction to Other paid-in capital. See further discussion regarding these senior notes and the purchase contract adjustment payments at Note 9, Long-Term Debt. Upon settlement of a purchase contract, SPR will receive the stated amount of $50 on the purchase contract and will issue the required number of shares of common stock. The stated amount received will be credited to stockholders’ equity and allocated between the Common stock and Other paid-in capital accounts.

Prior to the issuance of common stock upon settlement of the purchase contracts, SPR expects that the PIES will be reflected in SPR’s earnings per share calculations using the treasury stock method. Under this method, the number of shares of common stock used in calculating earnings per share is deemed to be increased by the excess, if any, of the number of shares of common stock issuable upon settlement of the purchase contracts over the number of shares that could be purchased by SPR in the market at the average closing price during the relevant period using the proceeds receivable upon settlement.

As of December 31, 2002, 3,441,166 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees’ Stock Purchase Plan (ESPP), and Executive Long-Term Incentive Plan (ELTIP). The ELTIP for key management employees allows for the issuance of SPR’s common shares to key employees through December 31, 2003, which can be earned and issued after December 31, 2003. This Plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares and bonus stock. SPR also provides an ESPP to all of its employees meeting minimum service requirements. Employees can choose twice each year (offering date) to have up to 15% of their base earnings withheld to purchase SPR common stock. The purchase price of the stock is 90% of the market value on the offering date or 100% of the market price on the execution date, if less. The Non-employee Director Stock Plan provides that a portion of SPR’s outside directors’ annual retainer be paid in SPR common stock. SPR records the costs of these plans in accordance with Accounting Principles Board Opinion Number (APB No.) 25. In addition, in 1996 the Company eliminated its outside director retirement plan and converted the present value of each director’s vested retirement benefit to phantom stock based on the stock price at the time of conversion. Phantom stock earns dividends, also payable in phantom stock, which are recorded in each Director’s phantom account. The

value of these accounts is issued in stock or cash, at the election of the Board, at the time the Director leaves the Board.

The changes in common stock and additional paid-in capital for 2002, 2001 and 2000, are as follows (dollars in thousands):


	Shares Issued						Amount

	2002		2001		2000		2002		2001		2000

Public Offering		—		23,575,000		—	$	—	$	340,364	$	—
Merger Exchange		—		—		—		—		—		—
CSIP/DRP		—		—		5,389		—		—		237
ESPP and other		66,873		60,319		55,268		455		361		1,055

		66,873		23,635,319		60,657	$	455	$	340,725	$	1,292

Subsequent Events

In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 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 2,095,650 of its PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933. Of the shares issued in these transactions, 7,565,506 shares represented the then current conversion value of the PIES.

On February 14, 2003, SPR issued $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually in arrears. SPR may redeem some or all of the notes for cash at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities that are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. The proceeds will be used to redeem approximately $133 million of its floating rate notes due April 20, 2003 and for general corporate purposes.

The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR’s common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes in shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the trading price of SPR’s common stock for a certain period prior to conversion. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval not later than 180 days after the date of issuance of the Convertible Notes for approval to issue and deliver shares of SPR’s common stock in lieu of the cash payment component of the conversion price of the Convertible Notes.

NOTE 8. PREFERRED STOCK AND PREFERRED TRUST SECURITIES

Sierra Pacific Power Company

Preferred Stock

SPPC’s Restated Articles of Incorporation, as amended on August 19, 1992, authorize an aggregate amount of 11,780,500 shares of preferred stock at any given time.

SPPC’s preferred stock is superior to SPPC’s common stock with respect to dividend payments (which are cumulative) and liquidation rights.

On January 30, 2003, a dividend of $975,000 ($0.4875 per share) was declared on SPPC’s preferred stock. The dividend is payable on March 1, 2003, to holders of record as of February 14, 2003.

The following table indicates the dollar amount and number of shares of SPPC preferred stock outstanding at December 31 of each year:


		Amount				Shares Outstanding

(Dollars in thousands)		2002		2001		2002		2001

Preferred Stock
Not subject to mandatory redemption
SPPC Class A Series I		$	50,000	$	50,000		2,000,000		2,000,000

	Total Preferred Stock	$	50,000	$	50,000		2,000,000		2,000,000

Nevada Power Company

Preferred Trust Securities

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, June, September and December of each year. Interest payments made by NPC in respect of the QUIPS 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.

The following table indicates the principal amount and number of shares of NPC preferred trust securities outstanding at December 31 of each year:


		Amount				Shares Outstanding

(Dollars in thousands)		2002		2001		2002		2001

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

	Total Preferred Trust Securities	$	188,872	$	188,872		233,656		233,656

Sierra Pacific Resources

SPR has issued neither preferred stock nor preferred trust securities.

NOTE 9. LONG-TERM DEBT

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

Nevada Power Company

On May 24, 2001, NPC issued $350 million of its 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011. The bonds were issued with registration rights under and secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001 that is subject to the prior lien of NPC’s Indenture of

Mortgage dated as of October 1, 1953. On January 29, 2002, NPC exchanged these bonds for identical bonds, registered under the Securities Act of 1933.

On June 12, 2001, $150 million of NPC’s floating rate notes matured and were paid in full.

On August 20, 2001, $100 million of NPC’s floating rate notes matured and were paid in full.

On September 20, 2001 and October 15, 2001, NPC issued an aggregate total of $210 million of 6% unsecured notes due September 15, 2003. Interest on the notes is payable on March 15 and September 15 of each year. These notes are not entitled to any sinking fund and are non-callable.

On October 18, 2001, NPC issued $140 million of its General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003.

On May 13, 2000, NPC issued a General and Refunding Mortgage Bond, Series D, due April 15, 2004, in the principal amount of $130 million, for the benefit of the holders of NPC’s 6.20% Senior Unsecured Notes, Series B, due April 15, 2004. The Senior Unsecured Notes Indenture required that in the event that NPC issued debt secured by liens on NPC’s operating property, in excess of 15% of its Net Tangible Assets or Capitalization (as both terms are defined in the Senior Unsecured Notes Indenture), NPC would equally and ratably secure the Senior Unsecured Notes. NPC triggered this negative pledge covenant on April 23, 2002, when it borrowed certain amounts under its secured credit facility.

On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage Bonds in the aggregate principal amount of $15 million.

On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for net proceeds of $235.6 million. The Series E Notes, which were issued with registration rights, were exchanged for registered notes in January 2003. The proceeds of the issuance were used to pay off NPC’s $200 million credit facility and for general corporate purposes. The Series E Notes will mature October 15, 2009.

As discussed in Note 13, Dividend Restrictions, NPC’s Series E Notes limit the amount of dividends that NPC may pay to SPR. The terms of the Series E 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, and certain letters of credit issued to support NPC’s obligations with respect to energy suppliers.

If NPC’s Series E 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 E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade.

Among other things, the Series E 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 E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

Sierra Pacific Power Company

On April 27, 2001, Washoe County, Nevada issued for SPPC’s benefit $80 million of Water Facilities Refunding Revenue Bonds, Series 2001, due March 1, 2036. The bonds bear interest at a term rate of 5.75% per annum from their date of issuance to April 30, 2003. Beginning May 1, 2003, the method of determining the interest rate on the bonds may be converted from time to time in accordance with the related Indenture so that such bonds would, thereafter, bear interest at a daily, weekly, flexible, term or auction rate. The bonds were issued to refund $80 million of Washoe County variable rate Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 on April 30, 2001. On June 11, 2001, SPPC completed the sale of its water business assets including the Project financed by the sale of the bonds. Although SPPC no longer owns the Project, SPPC will continue to bear the obligations and payments for the bonds under the terms of the Financing Agreement dated as of March 1, 2001, between SPPC and Washoe County, Nevada. These bonds will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest.

On May 24, 2001, SPPC issued $320 million of its 8.00% General and Refunding Mortgage Bonds, Series A, due June 1, 2008. The bonds were issued with registration rights under and secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001 that is subject to the prior lien of SPPC’s Indenture of Mortgage dated as of December 1, 1940. On January 29, 2002, SPPC exchanged these bonds for identical bonds, registered under the Securities Act of 1933.

On June 12, 2001, $200 million of SPPC’s floating rate notes matured and were paid in full. The floating rate notes were issued on June 9, 2000, and the net proceeds of the $200 million issue were used to redeem $100 million of floating rate notes on July 14, and the remaining proceeds were used to reduce the amount of SPPC’s commercial paper outstanding under the program established in July 1999.

On December 17, 2001, $17 million of SPPC’s MTN Series D matured and were paid in full.

On May 23, 2002, SPPC satisfied its obligations with respect to its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended.

On October 30, 2002 SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC’s $150 million credit facility, which was secured by a $150 million Series B General and Refunding Mortgage Bond.

As discussed in Note 13, Dividend Restrictions, SPPC’s Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. SPPC’s Term Loan Agreement also 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. SPPC’s Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through

September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter. As of December 31, 2002, SPPC was in compliance with these financial covenants. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005.

Sierra Pacific Resources

On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate PIES. Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50. The senior notes are pledged as collateral to secure each holder’s obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes.

Each holder of Corporate PIES is entitled to receive quarterly payments consisting of purchase contract adjustment payments and interest on the senior unsecured notes. The Corporate PIES have a combined rate of 9.0%, which is comprised of the coupon on the senior note of 7.93% and the stated rate of the purchase contract adjustment payments of 1.07%. Interest on the senior unsecured notes began to accrue on November 16, 2001, and quarterly interest payments will be made each quarter beginning with the first payment, which was made on February 15, 2002. All senior unsecured notes will be remarketed beginning on August 10, 2005, up to and including November 1, 2005, and, if necessary, on November 9, 2005, unless holders of senior notes that are not part of a Corporate PIES elect not to have their senior notes remarketed. Upon remarketing, the interest rate will be reset and the senior notes will accrue interest at the reset rate after the remarketing settlement date. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations. If any senior notes remain outstanding after the Purchase Contract Settlement Date, SPR will pay interest payments on those senior notes until their maturity on November 15, 2007.

Purchase contract adjustment payments will accrue from November 16, 2001. Holders received the first quarterly purchase contract adjustment payments of $0.1323 per unit ($913,000 in aggregate) on February 15, 2002, and will receive payments of $0.1338 per unit ($923,000 in aggregate) for each subsequent quarter. Upon issuance, a liability for the present value of the purchase contract adjustment payments, approximately $13.7 million, was recorded in Other Deferred Credits, with a corresponding reduction to Other Paid-in-Capital. As of December 31, 2002, the purchase contract adjustment payment liability was $10.5 million.

On April 20, 2002, $100 million of SPR’s floating rate notes matured and were paid in full.

In January 2003, SPR acquired $8,750,000 aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act.

On February 5, 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 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 $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually. SPR may redeem some or all of the notes at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. The proceeds will be used to redeem approximately $133 million of its floating rate notes due April 20, 2003 and for general corporate purposes. See Note 7, Common Stock and Other Paid-In Capital for additional information regarding the terms of the convertible notes.

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.

Sierra Pacific Communications

Sierra Touch America LLC (STA), a partnership between SPC and Touch America, formerly Montana Power Company, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America, subject to successful completion of the construction, in exchange for SPC’s partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total purchase price of $48.5 million. The promissory note accrues interest at 8% per annum. The first of twelve monthly payments of $3.3 million will commence on July 31, 2003 and continue until June 30, 2004, at which time all outstanding amounts will be due and payable. The promissory note is secured by all of SPC’s assets, and prepayments will shorten the length of the loan, but not reduce the installment payments.

As of December 31, 2002 NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years is shown below (in thousands of dollars):


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

	2003	$	354,677		$	101,400		$	216,818	$	672,895
	2004		135,570			3,400			14,498		153,468
	2005		6,091			100,400			300,000		406,491
	2006		6,509			52,400			—		58,909
	2007		5,949			2,400			345,000		353,349

			508,796			260,000			876,316		1,645,112
Thereafter			1,348,384			760,250			—		2,108,634

			1,857,180			1,020,250			876,316		3,753,746
Unamortized (Disc.)/Prem.			(13,906	)		(4,062	)		—		(17,968	)

Total		$	1,843,274		$	1,016,188		$	876,316	$	3,735,778

The preceding table includes obligations related to the following capital lease obligations.

In 1984, NPC sold its administrative headquarters facility, less furniture and fixtures, for $27 million and entered into a 30-year capital lease of that facility with five-year renewal options beginning in year 31. The fixed rental obligation for the first 30 years is $5.1 million per year. Also, NPC has a purchase power contract with Nevada Sun-Peak Limited Partnership. The contract contains a buyout provision for the facility at the end of the contract term in 2016. The facility is situated on NPC property.

Future cash payments for these leases, combined, as of December 31, 2002, were as follows (dollars in thousands):


2003	$	4,664
2004		5,557
2005		6,076
2006		6,494
2007		5,932
Thereafter		44,536

NOTE 10. TAXES

Sierra Pacific Resources

The following reflects the composition of taxes on income from continuing operations (in thousands of dollars):


			2002			2001			2000

As Reflected in Statement of Income
	Federal income taxes		$	(167,935	)	$	1,400		$	(31,684	)
	State income taxes			—			(3,164	)		446

		Federal Income Taxes on Operating Income		(167,935	)		(1,764	)		(31,238	)
	Other income - net			4,058			14,870			511

		Total	$	(163,877	)	$	13,106		$	(30,727	)

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):


	2002			2001			2000

Income/(Loss) from continuing operations	$	(300,851	)	$	32,898		$	(46,253	)
Total income tax expense (benefit)		(163,877	)		13,106			(30,727	)

		(464,728	)		46,004			(76,980	)
Statutory tax rate		35	%		35	%		35	%

Expected income tax expense (benefit)		(162,655	)		16,101			(26,943	)
Depreciation related to difference in costs basis for tax purposes		3,081			2,944			2,962
Allowance for funds used during construction - equity		112			85			151
Tax benefit from the disposition of assets		(48	)		(111	)		(175	)
ITC amortization		(3,454	)		(3,454	)		(1,824	)
State taxes (net of federal benefit)		—			(2,057	)		(1,170	)
Pension benefit plan		1,400			697			887
Other - net		(2,313	)		(1,099	)		(4,615	)

	$	(163,877	)	$	13,106		$	(30,727	)

Effective tax rate		35.3	%		28.9	%		39.9	%

The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars):


		2002		2001

Deferred Federal Income Tax Liabilities:
	Allowance for funds used during construction - debt	$	16,281	$	12,496
	Bond redemptions		11,132		11,508
	Excess of tax depreciation over book depreciation		555,811		401,358
	Severance programs		5,019		5,299
	Tax benefits flowed through to customer		163,889		169,738
	Deferred energy		339,640		430,812
	Ad Valorem Taxes		3,336		172
	Other		19,020		23,797

			1,114,128		1,055,180

Deferred Federal Income Tax Assets:
	Net operating loss carryforward		281,866		189,238
	Avoided interest capitalized		32,319		23,661
	Employee benefit plans		13,421		12,006
	Reserve for bad debt		15,121		13,761
	Contributions in aid of construction and customer advances		109,877		104,395
	Gross-ups received on contribution in aid of construction and customer advances		16,665		11,976
	Excess deferred income taxes		16,460		18,656
	Unamortized investment tax credit		26,258		28,046
	Other Accumulated Comprehensive Income - Additional minimum pension liability		24,905		—
	Contract Termination Reserve		109,408		—
	Other		7,446		(882	)

			653,746		400,857

TOTAL		$	460,382	$	654,323

SPR’s balance sheets contain a net regulatory asset of $121.3 million at year-end 2002 and $123.0 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $163.9 million at year-end 2002 and $169.7 million at year-end 2001, due to flow-through of the tax benefits of temporary differences. Offset against these amounts are future revenues to be refunded to customers (a regulatory liability), consisting of $16.5 million at year-end 2002 and $18.7 million at year-end 2001, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $26.2 million at year-end 2002 and $28.0 million at year-end 2001 due to unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to SPR. These items reduce rate base and, therefore, are benefits passed through to customers. However, because SPR had a net operating loss for tax purposes in 2001 and 2002, some of this benefit could not be utilized (i.e., deferred energy).

In March 2002, NPC received a federal income tax refund of $79.3 million. Additionally, SPR and the Utilities received $105.7 million of refunds in the second quarter of 2002. These refunds were the result of income tax losses generated in 2001. Federal legislation passed in March 2002 changed the allowed carry-back of these losses from two years to five years. This change permitted SPR and the Utilities to accelerate the receipt of a portion of their income tax receivables sooner than expected. The remaining income tax losses of $281.9 million as of December 31, 2002, may be utilized in future periods to reduce taxes payable to the extent

that SPR and the Utilities recognize taxable income. The carryforward period for net operating losses incurred is 20 years, and as such the losses incurred in the years ended 12/31/2000, 2001, and 2002 will expire in 2020, 2021, and 2022 respectively.

For the year 2000, all inter-company income tax related payables and receivables due to/from affiliates were paid in full as of 12/31/2000. For the year 2001, SPR owed the following income-tax related balances to affiliates: SPPC $62.1 million and NPC $18.6 million. For the year 2001, SPR had a receivable from all other subsidiaries of $8.5 million. There were no income tax-related inter-company payables and receivables due to/from affiliates for the year ended December 31, 2002.

The consolidated amount of current and deferred tax expense is allocated among SPR and its subsidiaries on a pro rata basis based on separate company taxable income. Any benefit or detriment associated with the consolidation of the income tax return is also allocated among SPR and its subsidiaries one a pro rata basis based on separate company taxable income.

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the Internal Revenue Service on a regular basis. The IRS began an audit of the company’s consolidated income tax returns in the third quarter of 2002. The years under examination include the separate company returns for NPC and its subsidiaries for 1997 and 1998 and the consolidated returns for SPR and its subsidiaries for 1997 through 2001. The focus of the examination is the net operating losses generated in 2000 and 2001 and carried back to earlier years. The losses reported in 2000 and 2001 are mainly due to the deductions claimed for purchased fuel and purchase power.

The losses claimed on the tax returns are mainly timing differences, and as such, are not expected to cause a material impact on SPR’s, NPC��s or SPPC’s future income statements if it is determined they are allowable in a subsequent period. No Notices of Proposed Adjustment have been received to date.

NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2002, carrying amount for cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments.

The total fair value of SPR’s consolidated long-term debt at December 31, 2002, is estimated to be $2.66 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPR for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $3.386 billion as of December 31, 2001. The estimated fair value of SPR’s consolidated preferred trust securities is $139.8 million at December 31, 2002. The fair value of SPR’s consolidated preferred trust securities was estimated to be $181.5 million at December 31, 2001.

NOTE 12. SHORT-TERM BORROWINGS

Sierra Pacific Resources

On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility in connection with the amendment of NPC’s $200 million unsecured revolving credit facility, discussed below.

Nevada Power Company

On November 29, 2001, NPC put into place a $200 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. As a result of NPC’s rate case decisions (discussed in Note 3, Regulatory Events) and the credit downgrades by S&P and Moody’s, which occurred on March 29 and April 1, 2002, respectively, the banks participating in NPC’s credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 3, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent for the credit facility.

As of September 30, 2002, NPC had borrowed the entire $200 million of funds available under its credit facility at an average interest rate of 3.72%.

On October 30, 2002, NPC paid in full and terminated its $200 million credit facility and retired its Series C, General & Refunding Bond which secured the credit facility with the proceeds from the issuance of NPC’s $250 million aggregate principal amount of 10 7/8% General and Refunding Notes, Series E, due 2009.

On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. 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 receivables. Lehman Brothers Holding, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. 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. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. As of December 31, 2002, this facility has not been activated. NPC does not expect to activate this facility in the foreseeable future.

Sierra Pacific Power Company

On November 29, 2001, SPPC put into place a $150 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. Under this credit facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility.

As of September 30, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, and to maintain a cash balance at SPPC at an average interest rate of 3.69%.

On October 31, 2002, SPPC paid off and terminated its $150 million credit facility and retired its Series B, General & Refunding Bond which secured the credit facility with a combination of cash on hand and proceeds from its $100 million Term Loan Facility.

On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC 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. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. 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 December 31, 2002 this facility has not been activated.

NOTE 13. 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 bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $237 million as of December 31, 2002), 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. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock.

Series E Notes. NPC’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, 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 the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E 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 E Notes,

•		NPC can meet a fixed charge coverage ratio test, 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 Series E Notes, plus

	•		100% of NPC’s aggregate net cash proceeds from 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 are upgraded to investment grade by both Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s Rating Group, Inc. (S&P), these dividend restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade.

Accounts Receivable Facility. On October 29, 2002, NPC established an accounts receivable purchase facility. 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.

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 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 December 31, 2002, NPC’s equity ratio was 36.1%.

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 not clear, it could be interpreted to impose an additional material limitation on a utility’s ability, in the absence of retained earnings, to pay dividends.

Sierra Pacific Power Company

Term Loan Agreement. SPPC’s Term Loan Agreement dated October 30, 2002, 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:

	•		(i) 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

	•		(ii) 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. 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 not clear, it could be interpreted to impose an additional material limitation on a utility’s ability, in the absence of retained earnings, to pay dividends.

NOTE 14. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

SPR has pension plans covering substantially all employees. Benefits are based on years of service and the employee’s highest compensation for a period prior to retirement. SPR also has other postretirement plans which provide medical and life insurance benefits for certain retired employees. The following table provides a reconciliation of benefit obligations, plan assets and the funded status of the plans; the market related value of the plan assets equals fair value. This reconciliation is based on a September 30 measurement date (dollars in thousands).


							Other Postretirement
	Pension Benefits						Benefits

	2002			2001			2002			2001

Change in benefit obligations
Benefit obligation, beginning of year	$	360,677		$	348,135		$	75,443		$	77,790
Service cost		11,954			13,494			1,287			1,922
Interest cost		27,733			27,742			5,599			6,358
Participant contributions		—			—			590			466
Plan amendment & special termination		7,938			476			—			—
Actuarial loss (gain)		50,670			6,864			56,189			(5,201	)
Special Termination Benefits		—			394			—			—
Acquisitions and divestiture		—			—			—			(1,231	)
Benefits paid		(29,997	)		(36,428	)		(6,938	)		(4,661	)

Benefit obligation, end of year	$	428,975		$	360,677		$	132,170		$	75,443

Change in plan assets
Fair value of plan assets, beginning of year	$	275,305		$	349,153		$	61,407		$	81,900
Actual return (loss) on plan assets		(23,090	)		(39,320	)		(6,817	)		(15,797	)
Company contributions		16,616			1,900			183			730
Participant contributions		—			—			590			466
Acquisition and divestiture		—			—			—			(1,231	)
Benefits paid		(29,997	)		(36,428	)		(6,937	)		(4,661	)

Fair value of plan assets, end of year	$	238,834		$	275,305		$	48,426		$	61,407

Funded Status, end of year	$	(190,142	)	$	(85,373	)	$	(83,744	)	$	(14,036	)
Unrecognized net actuarial (gains) losses		154,222			61,750			61,553			(5,365	)
Unrecognized prior service cost		17,001			10,366			724			—
Unrecognized net transition obligation		—			—			9,311			10,280
Contributions made in 4th quarter		24,495			11,917			—			—

Prepaid (accrued) pension and postretirement benefit obligations	$	5,576		$	(1,340	)	$	(12,156	)	$	(9,121	)

Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following:


							Other Postretirement
	Pension Benefits						Benefits

	2002			2001			2002			2001

Prepaid pension asset	$	19,813		$	14,051			N/A			N/A
Accrued benefit liability		(14,237	)		(15,391	)	$	(12,156	)	$	(9,121	)
Intangible asset		17,001			—			N/A			N/A
Accumulated other comprehensive income		72,550			1,395			N/A			N/A
Additional minimum liability		(89,551	)		(1,395	)		N/A			N/A

Net amount recognized		5,576			(1,340	)		(12,156	)		(9,121	)

The weighted-average actuarial assumptions as of the measurement date were as follows:


										Other Postretirement
	Pension Benefits									Benefits

	2002			2001			2000			2002			2001			2000

Discount rate		6.75	%		7.50	%		8.00	%		6.75	%		7.50	%		8.00	%
Expected return on plan assets		8.50	%		8.50	%		8.50	%		8.50	%		8.50	%		8.50	%
Rate of compensation increase		4.50	%		4.50	%		4.50	%		N/A			N/A			N/A

SPR has assumed a health care cost trend rate of 6% for 2002 and all future years.

Net periodic pension and other postretirement benefit costs include the following components:


		Pension Benefits

		2002			2001			2000

Service cost		$	11,954		$	13,494		$	11,907
Interest cost			27,733			27,742			26,469
Expected return on assets			(22,768	)		(28,806	)		(27,186	)
Amortization of:
	Transition asset		—			—			—
	Prior service costs		1,676			1,195			1,201
	Actuarial losses		2,252			200			159

Net periodic benefit cost			20,847			13,825			12,550
Special termination charges			1,646			394			—

Total net benefit cost		$	22,493		$	14,219		$	12,550


		Other Postretirement Benefits

		2002			2001			2000

Service cost		$	1,287		$	1,922		$	1,775
Interest cost			5,599			6,358			5,829
Expected return on assets			(5,044	)		(6,774	)		(5,327	)
Amortization of:
	Prior service costs		187			—			—
	Transition obligation		969			969			968
	Actuarial gains		—			—			(598	)

Net periodic benefit cost			2,998			2,475			2,647
	Special termination charges		58			—			—

Total net benefit cost		$	3,056		$	2,475		$	2,647

The assumed health care cost trend rate has a significant effect on the amounts reported. A one percentage point change in the assumed health care cost trend rate would have had the following effects on 2002 service and interest costs and the accumulated postretirement benefit obligation at year end:


One percentage point change	Increase		Decrease

Effect on service and interest components of net periodic cost	$	1,491	$	(1,206	)
Effect on accumulated postretirement benefit obligation	$	14,886	$	(12,324	)

NOTE 15. STOCK COMPENSATION PLANS

At December 31, 2002, Sierra Pacific Resources had several stock-based compensation plans which are described below.

SPR’s executive long-term incentive plan for key management employees, which was approved by shareholders on May 16, 1994, provides for the issuance of up to 750,000 of SPR’s common shares to key employees through December 31, 2003. On June 19, 2000, shareholders approved an increase of 1,000,000 shares for the executive long-term incentive plan. The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2002, SPR issued nonqualified stock options, performance shares, and restricted stock under the long-term incentive plan.

Non-Qualified Stock Options

Nonqualified stock options granted during 2002 were issued at an option price not less than market value at the date of the grants. The grants awarded in January and December vest to the participants 33% per year over a three year period from the grant date; the remaining grants awarded in 2002, vest to the participants 100% one year from the grant date. All grants may be exercised for a period not exceeding ten years from the grant date. The options may be exercised using either cash or previously acquired shares, valued at the current market price, or a combination of both.

A summary of the status of SPR’s nonqualified stock option plan as of December 31, 2002, 2001, and 2000, and changes during the year is presented below:


			2002				2001				2000

					Weighted-				Weighted-				Weighted-
					Average Exercise				Average Exercise				Average Exercise
Nonqualified Stock Options			Shares		Price		Shares		Price		Shares		Price

Outstanding at beginning of year				1,213,958	$	18.28		799,428	$	19.94		839,442	$	24.33
Granted				502,380	$	14.05		414,530	$	15.08		400,000	$	16.00
Exercised				—		—		—		—		14,107	$	14.28
Forfeited				197,232	$	18.07		—		—		425,907	$	25.07
Outstanding at end of year				1,519,106	$	16.91		1,213,958	$	18.28		799,428	$	19.94
Options exercisable at year-end				601,371	$	19.52		262,533	$	23.03		202,394	$	22.66
Weighted-average grant date fair value of options granted¹:
	Average of all grants for:
		2002	$	4.56
		2001					$	3.83
		2000									$	4.10

The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants issued in 2002, 2001 and 2000:


	Average			Average			Average Risk-
	Dividend			Expected			Free Rate of			Average
Year of Option Grant	Yield			Volatility			Return			Expected Life

2002		0.00	%		38.23	%		5.03	%	10 years
2001		4.99	%		32.31	%		5.32	%	10 years
2000		4.81	%		30.49	%		6.14	%	9.6 years

The following table summarizes information about nonqualified stock options outstanding at December 31, 2002:


				Options Outstanding			Options Exercisable

		Average		Number		Remaining	Average		Number
		Exercise		Outstanding		Contractual	Exercise		Exercisable
Year of Grant		Price		at 12/31/02		Life	Price		at 12/31/02

	1994	$	14.24		8,003	1 year	$	14.24		8,003
	1995	$	13.02		9,010	2 years	$	13.02		9,010
	1996	$	16.23		7,485	3 years	$	16.23		7,485
	1997	$	19.97		33,428	4 years	$	19.97		33,428
	1998	$	24.93		56,160	5 years	$	24.93		56,160
	1999	$	25.11		222,120	6 - 6.6 years	$	25.11		179,124
	2000	$	16.00		400,000	7 years	$	16.00		200,000
	2001	$	15.95		338,010	8 - 8.6 years	$	15.95		108,161
	2002	$	7.75		444,890	9 - 9.9 years	$	7.75		—
Weighted Average Remaining Contractual Life						7.54 years

Each participant was granted dividend equivalents for all 1996 and prior nonqualified option grants. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted from the date of grant through the exercise date. Dividend equivalents will be forfeited if options expire unexercised.

Performance Shares

In 2002, 2001 and 2000, SPR granted performance shares in the following numbers and initial values:


	1/1/02		1/1/01		8/4/00		1/1/00

Shares Granted		96,772		144,271		4,798		31,707
Value per Share	$	15.58	$	14.80	$	16.00	$	26.00

The actual number of shares earned by each participant is dependent upon SPR achieving certain financial goals over three-year performance periods. However, 66,100 shares included in the number granted on January 1, 2001, had a one-year performance period, from January 1 through December 31, 2001. The value of all performance share grants, if earned, will be equal to the market value of SPR’s common shares as of the end of the performance periods. SPR, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof. The grant of 66,100 shares on January 1, 2001 would have been paid in SPR stock only, however, this grant has not been approved for payment by SPR Board of Directors.

Simultaneous with the grant of the performance shares above, each participant was granted dividend equivalents. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted throughout the performance period. Additionally, in order for dividend equivalents to be paid on the performance shares, certain financial targets must be met. Dividend equivalents will be forfeited if options expire unexercised.

Restricted Stock Shares

In 2002, SPR granted 4,500 restricted stock shares at an average grant price of $6.88 per share. The grants vest over 4 years at 25% per year.

During 2001, SPR granted 13,200 shares of restricted stock at an average grant price of $15.67 per share. The grants vest to the participants over 4 years at 25% per year. In 2002, according to the vesting schedule for each grant, 1,750 shares were issued under these grants.

In 2000, SPR granted 16,000 restricted stock shares at a grant price of $16.00 per share. The grant vests over 4 years with 4,000 shares becoming available in 2002, 4,000 shares in 2003, and 8,000 shares in 2004. In 2002, 4,000 shares were issued under this grant, in accordance with the vesting schedule. There is no performance criteria associated with the restricted stock grants, except for continued employment with SPR or its subsidiaries, and all grants were issued with an entitlement to dividend equivalents.

Employee Stock Purchase Plan

Upon the inception of SPR’s employee stock purchase plan, SPR was authorized to issue up to 400,162 shares of common stock to all of its employees with minimum service requirements. On June 19, 2000, shareholders approved an additional 700,000 shares for distribution under the plan. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase SPR’s common stock. The purchase price of the stock is 90% of the market value on the offering commencement date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan SPR sold 73,321, 33,830 and 46,773 shares to employees in 2002, 2001, and 2000, respectively. For purposes of determining the pro forma disclosure, compensation cost has been estimated for the employees’ purchase rights on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for 2002, 2001 and 2000:


	Average			Average			Average Risk-			Weighted
	Dividend			Expected			Free Rate of			Average Fair
Year	Yield			Volatility			Return			Value

2002		0.00	%		38.00	%		3.12	%	$	1.45
2001		5.01	%		32.43	%		2.82	%	$	2.72
2000		4.72	%		30.97	%		5.86	%	$	3.03

Non-Employee Director Stock

The annual retainer for non-employee directors is $30,000, and the minimum amount to be paid in SPR stock is $20,000 per director. During 2002, 2001 and 2000, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 18,540, 14,573, and 16,915 shares, and $160,000, $210,000, and $250,000.

NOTE 16. DISCONTINUED OPERATIONS AND DISPOSAL OF LONG-LIVED ASSETS

e·three and e·three Custom Energy Solutions

Effective January 1, 2002, SPR adopted SFAS No. 144. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met.

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.

The operations of e·three and CES discussed above are classified as discontinued operations in the accompanying consolidated statements of operations. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. The revenues associated with the discontinued operations were $6.4 million, $16.1 million and $11.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. The pretax income (loss) associated with the discontinued operations were $(1.8) million, $1.2 million and $0.6 million for each of the years ended December 31, 2002, 2001 and 2000, respectively. Income (losses) from operations of discontinued businesses include the operating results of e·three and CES of $(1.2) million, $0.7 million and $.3 million for the years ended December 31, 2002, 2001 and 2000, respectively.

The assets and liabilities associated with the discontinued operations of e·three and CES are segregated on the consolidated balance sheets at December 31, 2002 and 2001. The carrying amount of major asset and liability classifications are as follows:


	December 31, 2002		December 31, 2001

Investments and other property, net	$	9,488	$	10,276
Cash and cash equivalents		1,322		526
Accounts receivable		111		2,622
Materials and supplies		492		688
Current assets- Other		62		338
Goodwill		470		963
Deferred federal income taxes		731		91
Deferred charges - Other		186		173

	$	12,862	$	15,677

Long-term debt		—		68
Current maturities of long-term debt		68		—
Accounts payable		675		3520
Accrued salaries and benefits		30		—
Deferred credits - Other		14		29

	$	787	$	3,617

Sale of Water Business

In June 2001, SPPC closed the sale of its water business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million gain on the sale, net of the refund described below and net of income taxes of $18.2 million. Included in the sale were facilities for water storage, supply, transmission, treatment and distribution, as well as accounts receivable and regulatory assets. Accounts receivable consisted of amounts due from developers for distribution facilities. Regulatory assets consisted primarily of costs incurred in connection with the Truckee River negotiated water settlement. Transfer of hydroelectric facilities included in the contract of sale for an additional $8 million will require action by the CPUC. The sale agreement contemplates a second closing for the hydroelectric facilities to accommodate the CPUC’s review of the transaction. See Note 3, Regulatory Actions, for a discussion of California legislative and regulatory developments involving the hydroelectric facilities.

Pursuant to a stipulation entered into in connection with the sale and approved by the PUCN, SPPC was required to hold in trust for refund to customers $21.5 million of the proceeds from the sale. The refund was credited on the electric bills of SPPC’s former water customers over a fifteen-month period ending November 2002. Under a service contract with TMWA, SPPC provided customer service and billing services to TMWA until August 2002. SPPC continues to provide meter-reading services under a one-year contract renewable in one-year increments by TMWA through 2008.

Revenues from operations of the water business for the years ended December 31, 2001, and 2000 were $23 million and $57 million, respectively. The net income from operations of the water business, as shown in the Consolidated Statements of Operations of both SPR and SPPC, includes preferred dividends of $200,000 and $401,000 for the years ended December 31, 2001, and 2000, respectively. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying consolidated statements of operations.

Asset Sales

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 November 11, 2002, SPPC agreed to sell land located in Nevada County and Sierra County, California, commonly referred to as Independence Lake. The sale remains subject to review by a third party who retains certain rights, including water rights, after the sale is completed. Also, the sales agreement includes a due diligence review period of 180 days which allows the buyer to review and accept a variety of matters agreed to by both parties. The buyer may terminate the agreement during the review period by providing written notice or by allowing the review period to expire. The agreed upon sales price is $22 million and the transaction is expected to close, subject to the conditions described, in the second quarter of 2003. The carrying value of the property is approximately $108,000.

NOTE 17. COMMITMENTS AND CONTINGENCIES

Purchased Power

At December 31, 2002, NPC has six long-term contracts for the purchase of electric energy. Expiration of these contracts ranges from 2016 to 2024. SPPC has one long-term contract with an expiration date of 2009. Estimated future commitments under non-cancelable agreements (including agreements with Qualifying Facilities (QF’s) as of December 31, 2002 were as follows (dollars in thousands):


Purchased Power

		NPC		SPPC		Total
	2003	$	408,656	$	138,803	$	547,459
	2004		241,957		42,968		284,925
	2005		220,343		28,874		249,217
	2006		204,666		29,406		234,072
	2007		189,434		30,957		220,391
Thereafter			3,456,297		38,351		3,494,648

According to the regulations under the Public Utility Regulatory Policies Act, the Utilities are obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities. As of December 31, 2002, NPC had a total of 305 MWs of contractual firm capacity under contract with four QFs. The contracts terminate between 2022 and 2024. As of December 31, 2002, SPPC had a total of 109 MWs of maximum contractual firm capacity under 15 contracts with QFs. SPPC also has contracts with three projects at variable short-term avoided cost rates. SPPC’s long-term QF contracts terminate between 2006 and 2039.

Coal and Natural Gas

The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2003 to 2027. Estimated future commitments under non-cancelable agreements were as follows (dollars in thousands):


		Coal and Gas						Transportation

		NPC		SPPC		Total		NPC		SPPC		Total
	2003	$	37,818	$	31,699	$	69,517	$	36,606	$	61,733	$	98,339
	2004		27,040		15,364		42,404		42,285		60,651		102,936
	2005		9,605		15,830		25,435		28,946		56,001		84,947
	2006		2,829		16,302		19,131		28,946		53,174		82,120
	2007		1,007		0		1,007		28,946		50,270		79,216
Thereafter			4,029		0		4,029		337,312		318,493		655,805

Leases

SPPC has an operating lease for its corporate headquarters building. The primary term of the lease is 25 years, ending 2010. The current annual rental is $5.4 million, which amount remains constant until the end of the primary term. The lease has renewal options for an additional 50 years.

SPR’s estimated future minimum cash payments, including SPPC’s headquarters building, under non-cancelable operating leases as of December 31, 2002, were as follows (dollars in thousands):


Operating Leases

		NPC		SPPC		Other Subs		Total
	2003	$	2,263	$	8,357	$	479	$	11,099
	2004		1,170		7,080		476		8,726
	2005		869		6,425		380		7,674
	2006		181		6,177		147		6,505
	2007		119		6,173		147		6,439
Thereafter			459		55,153		2,086		57,698

Sale of Generation Assets

As a condition to its approval of the merger between SPR and NPC, the PUCN required the Utilities to file a Divestiture Plan for the sale of their electric generation assets. The PUCN approved a revised Divestiture Plan stipulation in February 2000. 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.

AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets 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 until 2006 any further divestiture of generation properties by California utilities, 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.

In addition, 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 amendment, AB 1235, AB 6 that would allow SPPC to complete the sale of the four hydroelectric units to TMWA. Section 851 of the Public Utilities Code requires review and approval of the sale by the CPUC. The sale of the Farad Hydroelectric Unit is conditioned on the completion of the reconstruction of the Farad dam and flume or assignment of SPPC insurance claim for reconstruction of the dam. The Farad Reconstruction Project is currently in the permitting phase with permits expected by mid-2003.

The sales agreements for the six bundles provided that they terminate eighteen months after their execution unless the parties agreed to an earlier termination. The parties could have extended the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which rendered the contracts impossible to perform, the Utilities engaged in discussions with the buyers of the generation assets regarding the formal termination of the sales agreements and the related energy buyback contracts and interconnection agreements. Those discussions ended without agreement to mutually terminate; however, all the contracts have now terminated in accordance with the contract provisions. As of December 31, 2002, the Utilities had incurred costs of approximately $20.1 million at NPC and $12.2 million at SPPC in order to prepare for the sale of generation assets. The Utilities requested recovery of these costs in each Utility’s respective general rate case filings with the PUCN. The PUCN delayed recovery of the divestiture costs to a future rate case request but did grant a carrying charge on the costs until such time as recovery is allowed.

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 $1.1 billion. As a 14% owner in Mohave, NPC’s cost could be $154 million.

NPC is currently evaluating and analyzing all of its options with regard to the Mohave project.

In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been approved by NDEP. NDEP is expected to identify remediation requirements of contaminated groundwater resulting from these evaporation ponds by July 2003. New pond construction and lining costs are estimated at $15 million.

At the Reid Gardner Station, the NDEP has 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. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system, which has been approved by NDEP, will be constructed beginning in April 2003 at an estimated cost of $150,000.

In May 1999, NDEP issued an order to eliminate the discharge of NPC’s Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan, which was approved in June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC will spend $789,000 to line existing ponds. This project was started in 2002 and is expected to be completed in the first quarter 2003.

In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the 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 prevails, capital expenditures and temporary outages of four 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. To date, the EPA has not issued additional requests for further information.

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 under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. The property is currently leased with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond.

Sierra Pacific Power Company

In September 1994 Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc. however; the contaminated material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which 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 has issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through December 31, 2002. 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 record the ultimate liabilities 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 has been removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. The Lahontan Regional Water Quality Control Board has approved closure without additional remediation pending a one-year monitoring period. Final closure is anticipated in December 2003.

Other Commitments and Contingencies

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. The conduits included in the line are to be sold to AT&T, PF Net Corporation, and STA. Construction is expected to be completed in the second quarter of 2003. The project sustained significant cost overruns and several complaints and mechanics liens have been filed by several contractors and subcontractors, including Williams Communications LLC, Bayport Pipeline Company, and Mastec North America. 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. Several of the mechanics lienors have named SPC as the owner of the project and Bayport Pipeline has suggested it may amend its complaint to name SPC.

SPPC owns a 345 kV transmission line that connects SPPC to the facilities of the Bonneville Power Administration (BPA) near Alturas, California. The Transmission Agency of Northern California (TANC) initiated proceedings in the United States District Court for the Eastern District of California and the United States Court of Appeals for the Ninth Circuit, in each case alleging that BPA’s construction of a small portion of the Alturas Intertie violated the Northwest Power Preference Act and is requesting an injunction prohibiting operation of the Alturas Intertie. The case before the Eastern District was dismissed for lack of jurisdiction. The case before the Ninth Circuit was dismissed for TANC’s failure to prosecute. In December 1999, TANC filed suit in the Superior Court of the State of California, Sacramento County, seeking an injunction against operation of the Alturas Intertie based on numerous allegations under state law, including inverse condemnation, trespass, private nuisance, and conversion. That case was removed to Federal Court and dismissed by the trial court.

The dismissal was affirmed by the Ninth Circuit Court of Appeals, and TANC has now filed a writ of certiorari with the United States Supreme Court. Management believes the final outcome of the appeal is not likely to have a material adverse effect on SPPC’s financial position or results of operation.

Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have 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 filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities’ proceedings under Section 206 of the Federal Power Act at the FERC. The Utilities have 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 unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets.

On December 19, 2002, the bankruptcy judge granted Enron’s motion for partial summary judgment on Enron’s claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron’s creditors and subject to refund depending on the outcome of the Utilities’ FERC cases on the merits. The Utilities made the deposit as required. The bankruptcy court denied the Utilities’ motion to stay the proceeding pending the outcome of the Utilities’ Section 206 case at the FERC and denied the Utilities’ motion to dismiss for lack of jurisdiction as to Enron’s claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron’s motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively pending the outcome of the case on the merits, and for judgment on the merits on Enron’s liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities’ motion to stay or dismiss Enron’s claim for liquidated damages relating to the undelivered power and set a hearing on Enron’s motion to dismiss the Utilities’ counterclaims for April 3, 2003. The Utilities are unable to predict the outcome of these motions. The United States District Court for the Southern District of New York also denied the Utilities’ motion to withdraw reference of the matter to the bankruptcy court without prejudice.

The bankruptcy court currently has under submission (1) Enron’s motion to dismiss the Utilities’ counterclaims, (2) Enron’s motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities’ motion to dismiss or stay proceeding on Enron’s claims relating to delivered power. Enron’s motion to dismiss the Utilities’ counterclaims is set for hearing on April 3, 2003. A decision adverse to the Utilities on Enron’s motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron’s claims on the merits for undelivered power, would have a material adverse effect on SPR’s and the Utilities’ 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.

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 is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims 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.

On September 30, 2002, plaintiffs Stephen A. Gordon and Gail M. Gordon filed a lawsuit in the District Court for Clark County, Nevada, seeking class action status for themselves and all shareholders of SPR against SPR and all of its directors for an alleged breach of fiduciary duty in failing to meaningfully evaluate and consider an alleged offer from the Southern Nevada Water Authority (SNWA) to purchase NPC. The suit seeks extraordinary relief in the form of an injunction requiring the directors to carefully evaluate and consider such offer, formation of a special stockholders committee to ensure fair and adequate evaluation procedures, and for unspecified damages and/or punitive damages in the event the SNWA withdraws its alleged offer before it can be carefully evaluated. SPR intends to vigorously defend the suit. No answer or responsive pleading has yet been required nor have plaintiffs moved for class certification. On September 30, 2002, plaintiff John Anderson filed a virtually identical lawsuit seeking the same relief. On March 21, 2003, plaintiffs’ counsel moved to consolidate the Gordon and Anderson cases with another virtually identical lawsuit filed by John Dedolph. SPR believes that the cases are without merit and plans to file motions to dismiss in the second quarter 2003.

On October 21, 2002, Bonneville Square and Union Plaza filed a complaint seeking class certification in the Eighth Judicial District Court for Clark County, Nevada, against NPC for fraud and misrepresentation for allegedly overcharging a certain class of customers for energy delivered over the past several years. Plaintiffs allege that NPC fraudulently placed its meters and measured energy delivered at a point prior to passing through transformers during which process a certain amount of energy is dissipated as heat, instead of placing the meters after they pass through the transformer. NPC’s motion to dismiss on jurisdictional grounds was denied and NPC is filing a writ before the Nevada Supreme Court and is being joined in by the PUCN, which agrees with NPC that it has exclusive jurisdiction over the suit. NPC denies that the placement of the meters was fraudulent and alleges that placement of the meters was mandated by either or both customer request or applicable tariff.

On April 22, 2002, Reliant Energy Services, Inc. (Reliant), filed and served a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which was consolidated in the Superior Court of the State of California. Plaintiffs in that case seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there is liability, it should be spread among all energy suppliers. The trial court has held all answers to cross-claims in abeyance until such time as it decides demurrers filed by all the defendants.

On May 3, 2002 and July 3, 2002, respectively, Reliant Resources and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002 and July 30, 2002, Reliant Resources 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. To date only Idaho has requested mediation of the contracts, which should be completed by the end of second quarter. NPC alleges that Idaho and Reliant Resources were participants in market manipulation in the West and therefore are not entitled to termination payments under the contract.

In August 2002, El Paso Merchant Energy (EPME) terminated contracts for energy it had delivered to NPC under a program that called for delayed payment of the full contract price. In October 2002, EPME asserted a claim against NPC for $19 million in damages representing the approximate amount unpaid under the contracts. NPC alleges that EPME’s termination resulted in net payments due to NPC under the WSPP liquidated damages provision as and for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. Both claims are subject to mandatory mediation under the WSPP, but neither party has requested mediation at the present time.

In connection with claims by their terminated energy suppliers, the Utilities established reserves, included in their Consolidated Balance Sheets in “Contract termination reserves,” totaling approximately $313 million, and pursuant to the deferred energy accounting provisions of AB 369, NPC and SPPC added approximately $228 million and $82 million, respectively, to their deferred energy balances for recovery in rates in future periods.

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 their financial positions, results of operations, or cash flows.

See Notes 3, 5, 6, 7, 8, 9, 12, and 14 for additional commitments and contingencies.

NOTE 18. SEGMENT INFORMATION

SPR operates three business segments (as defined by FASB Statement No. 131, Disclosure about Segments of an Enterprise and Related Information) providing regulated electric and natural gas service. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas services are provided in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.

The net assets and operating results of e·three are reported as discontinued operations in the financial statements for 2002, 2001 and 2000. The net assets and operating results of SPPC’s water business, divested in 2001, are reported as discontinued operations in the financial statements for 2001 and 2000. Accordingly, the segment information excludes financial information of e·three and SPPC’s water business.

Operational information of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which the primary financial measure is business segment operating income. The accounting policies of the business segments are the same as those described in Note 1, Summary of Significant Accounting Policies. Inter-segment revenues are not material.


															Reconciling
December 31, 2002	NPC Electric			SPPC Electric			Total Electric			Gas		All Other			Eliminations		Consolidated

Operating revenues	$	1,901,034		$	931,251		$	2,832,285		$	149,783	$	3,236				$	2,985,304
Operating income (loss)		(104,003	)		49,944			(54,059	)		5,348		16,662			—		(32,049	)
Operating income taxes		(133,411	)		(7,236	)		(140,647	)		314		(27,602	)				(167,935	)
Depreciation		98,198			70,190			168,388			6,183		155					174,726
Interest expense on long-term debt		98,886			62,004			160,890			4,470		69,172					234,532
Assets		4,068,522			2,064,749			6,133,271			208,752		429,963			124,989		6,896,975
Capital expenditures		294,480			90,343			384,823			14,984					—		399,807


												Reconciling
December 31, 2001	NPC Electric		SPPC Electric		Total Electric		Gas		All Other			Eliminations		Consolidated

Operating revenues	$	3,025,103	$	1,401,778	$	4,426,881	$	145,652	$	2,728				$	4,575,261
Operating income (loss)		144,364		71,219		215,583		7,749		(1,609	)		—		221,723
Operating income taxes		17,775		5,534		23,309		2,973		(28,046	)				(1,764	)
Depreciation		93,101		66,393		159,494		5,710		604					165,808
Interest expense on long term debt		81,599		50,071		131,670		5,128		51,321					188,119
Assets		4,704,606		2,357,548		7,062,154		264,108		580,696			85,320		7,992,278
Capital expenditures		200,852		116,713		317,565		16,041					—		333,606


															Reconciling
December 31, 2000	NPC Electric			SPPC Electric			Total Electric			Gas		All Other			Eliminations		Consolidated

Operating revenues	$	1,326,192		$	894,919		$	2,221,111		$	100,803	$	3,197				$	2,325,111
Operating income		74,182			31,989			106,171			13,420		6,094					125,685
Operating income taxes		(12,162	)		(3,944	)		(16,106	)		3,272		(18,404	)				(31,238	)
Depreciation		85,989			66,655			152,644			4,975		418					158,037
Interest expense on long term debt		64,513			23,435			87,948			4,318		42,270					134,536
Assets		3,407,751			1,722,725			5,130,476			151,905		61,768			333,759		5,677,908
Capital expenditures		204,505			117,785			322,290			14,490					23,350		360,130

The reconciliation of Capital expenditures for 2000 represents capital expenditures of the discontinued water business. The reconciliation of segment assets at December 31, 2002, 2001, and 2000 to the consolidated total includes the following unallocated amounts:


	2002		2001		2000

Other property	$	—	$	—	$	1,998
Cash		98,515		11,772		5,348
Current assets- other				50,862		29,852
Other regulatory assets		24,555		22,626		33,315
Net assets - discontinued operations		—		—		261,479
Deferred charges- other		1,919		60		1,767

	$	124,989	$	85,320	$	333,759

NOTE 19. DERIVATIVES AND HEDGING ACTIVITIES

Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, both issued by the Financial Accounting Standards Board. 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.

However, in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” regulatory assets and liabilities are established to the extent that such derivative gains and losses are recoverable or payable through future rates. Because of this accounting treatment, the Utilities will not apply hedge accounting to their electricity and natural gas derivatives. SPR and the Utilities have adopted cash flow hedge accounting for other derivative instruments not subject to regulatory treatment. The transition adjustments resulting from adoption of SFAS No. 133 related to the other derivative instruments not subject to regulatory treatment was reported as the cumulative effect of a change in accounting principle in Other Comprehensive Income of SPR and the Utilities.

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.

Derivatives used to manage interest rate risk include interest rate swaps designed to moderate exposure to interest-rate changes and lower the overall cost of borrowing. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003.

At December 31, 2002, the fair value of the derivatives resulted in the recording of $30 million, $29 million and $1 million in risk management assets and $74 million, $30 million and $44 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. Also, $45 million, $2 million and $43 million in net risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively at December 31, 2002. In addition, for the twelve months ended December 31, 2002, 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 will be reclassified into earnings when the related transactions are settled or terminate. Accordingly, $7.3 million relating to SPR’s terminated interest rate swap was reclassified into earnings during the twelve-month period ended December 31, 2002.

The effects of the adoption of SFAS No. 133 on comprehensive income have been reported in the consolidated statements of comprehensive income.

NOTE 20. CHANGE IN ACCOUNTING FOR GOODWILL

SFAS No. 142, adopted by SPR, NPC and SPPC on January 1, 2002, changed the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. Upon adoption, SPR ceased amortizing goodwill.

SPR’s Consolidated Balance Sheet as of December 31, 2002, includes approximately $306 million of goodwill pertaining to regulated operations resulting from the July 28, 1999 merger between SPR and NPC, net of approximately $19.7 million of amortization that has been deferred as a regulatory asset. The PUCN stipulation approving the merger allows for future recovery of this goodwill in rates charged to customers of SPR’s regulated utility subsidiaries, NPC and SPPC, provided that NPC and SPPC demonstrate that merger savings exceed merger costs. The amount and timing of the recovery of this goodwill will be determined by the outcome of general rate cases expected to be filed by the Utilities with the PUCN in late 2003. For additional information, see Note 2, SPR and NPC Merger.

SPR’s Consolidated Balance Sheet as of December 31, 2001, included approximately $6.2 million of goodwill related to unregulated operations that are reported under the “All Other” segment in Note 18. SFAS No. 142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was used to determine the fair value of each reporting unit of SPR’s unregulated operations. The reporting units included in SPR’s unregulated operations evaluated for goodwill impairment were LOS, SPC, TGPC, and “Energy” (a reporting unit consisting of Sierra Energy Company dba e·three and Sierra Pacific Energy Company). As a result of the impairment testing, which included revenue forecasts and appraisal of assets, SPR recorded a transitional goodwill impairment charge of approximately $1.7 million ($1.6 million, net of applicable taxes) as a cumulative effect of a change in accounting principle on SPR’s Consolidated Statements of Operations for the twelve months ended December 31, 2002. The goodwill impairment recognized by reporting unit was approximately $131,000, $40,000 and $1.5 million for LOS, SPC and “Energy,” respectively. Goodwill assigned to TGPC was determined not to be impaired.

The changes in the carrying amount of goodwill for the twelve-month period ended December 31, 2002 are as indicated. The balances below include $963,000 and $470,000 as of January 1, 2002, and December 31, 2002, respectively, of goodwill related to e·three which is reported in Assets of Discontinued Operations.


	Regulated		Unregulated
(In $000’s)	Operations		Operations			Total

Balance as of January 1, 2002	$	305,982	$	6,163		$	312,145
Impairment loss		—		(1,704	)		(1,704	)

Balance as of December 31, 2002	$	305,982	$	4,459		$	310,441

A reconciliation of SPR’s previously reported net income (loss) and earnings (loss) per share to the amounts adjusted for the adoption of SFAS No. 142 net of the related income tax effect follows:

(Dollars in Thousands, Except Per Share Amounts)


			Year ended December 31,
			2002			2001		2000

Earnings (Loss):
Applicable to Common Stock			$	(307,521	)	$	56,733	$	(39,780	)
	Add back amortization of goodwill, net of tax			—			137		142

As adjusted				(307,521	)		56,870		(39,638	)
	Add back cumulative effect of change in accounting principle, net of tax			1,566			—		—

As adjusted before cumulative effect of change in accounting principle			$	(305,955	)	$	56,870	$	(39,638	)

Basic and diluted earnings (loss) per share:
	As reported		$	(3.01	)	$	0.65	$	(0.51	)
		Add back amortization of goodwill, net of tax		—			—		—

	As adjusted			(3.01	)		0.65		(0.51	)
		Add back cumulative effect of change in accounting principle, net of tax		0.01			—		—

	As adjusted before cumulative effect of change in accounting principle		$	(3.00	)	$	0.65	$	(0.51	)

NOTE 21. PIÑON PINE

SPPC, through its wholly owned subsidiaries, Piñon Pine Corp., Piñon Pine Investment Co. and GPSF-B, owns Piñon Pine Company, L.L.C. (the LLC). The LLC was formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier available under Section 29 of the Internal Revenue Code. The entire project, which includes an LLC-owned gasifier, an SPPC-owned combined cycle generation facility and a post-gasification facility to partially cool and clean the syngas, is referred to collectively as the Piñon Pine Power Project (Piñon Pine). Construction of Piñon Pine was completed in June 1998.

Piñon Pine was co-funded by the Department of Energy (DOE) under an agreement between SPPC and DOE that expired December 31, 2000. The DOE funded approximately $167 million for construction, operation, and maintenance of the project. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $100 million as of December 31, 2002.

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. The scope of the study included evaluation of the potential modifications required to make the facility operational and reliable using several technology scenarios. The evaluation of each scenario included an estimate of the additional capital expenditures necessary for reliable operation of the facility, and the risks associated with that technology.

SPPC received a final report of the study in November 2002. The results of the study identified a number of potential modifications to the facility each with varying degrees of technical risk and cost. Modifications considered to provide the highest probability for successful operation of the facility generally were also estimated to be the highest cost options. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN’s approval of Piñon Pine as a demonstration project in an earlier resource plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC’s and SPR’s financial condition and results of operations.

NOTE 22. SUBSEQUENT EVENTS

See Notes 1, 3, 7, 8, 9, 16 and 17 for discussion of events occurring after December 31, 2002.

NOTE 23. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods. Dollars are presented in thousands except per share amounts.

FINANCIAL STATEMENT SCHEDULE

Sierra Pacific Resources
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2002, 2001 and 2000
(Dollars in Thousands)


		Provision for
		Uncollectible
		Accounts

Balance at January 1, 2000			6,475
	Provision charged to income (1)		14,879
	Amounts written off, less recoveries		(8,160	)

Balance at December 31, 2000		$	13,194

Balance at January 1, 2001			13,194
	Provision charged to income (2)		42,767
	Amounts written off, less recoveries		(16,626	)

Balance at December 31, 2001		$	39,335

Balance at January 1, 2002			39,335
	Provision charged to income		16,814
	Amounts written off, less recoveries		(11,965	)

Balance at December 31, 2002		$	44,184

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	Sierra Pacific Resources
	(Registrant)

Date: November 25, 2003	By:	/s/ John E. Brown

		John E. Brown
		Vice President, Controller

EXHIBIT INDEX

12.1 Ratios of Earnings to Fixed Charges

23.1 – Independent Auditors’ Consent

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