Sierra Pacific Resources 8-K

TABLE OF CONTENTS


	Item 5. Other Events
	Item 7. Financial Statements and Exhibits
Signatures
EX-12.1 Ratio of earnings to fixed charges
EX-23.1 Consent of Independent Registered Public Accounting Firm

Item 5. Other Events

Sierra Pacific Resources (“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, 2003 to reflect operations that have been discontinued since the time of the filing of that Form 10-K.

This Report is limited to the revisions to reflect certain businesses as discontinued operations and to update earnings per share calculations for the year ending December 31, 2003 to reflect SPR’s adoption of a new accounting standard for the quarter ended March 31, 2004. 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.

As previously disclosed in the Quarterly Report on Form 10-Q of SPR for the quarter ended March 31, 2004, on March 31, 2004, the Financial Accounting Standards Board ratified the consensus reached by its Emerging Issues Task Force (EITF) on EITF 03-06 “Participating Securities and the Two-Class Method under FASB Statement No. 128” (EITF 03-06). SPR adopted EITF 03-06 for the quarter ended March 31, 2004 and all prior periods presented.

Sierra Pacific Communications (“SPC”) was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC’s business activities have included the development of a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (the “Long Haul Assets”) and the development of Metro Area Networks (“MAN”) in Las Vegas and Reno, Nevada.

In keeping with management’s strategy to focus on its core utility business, SPR sold SPC’s MAN assets on June 30, 2004. SPC recognized a gain on the sale of assets of approximately $2.5 million (pretax) in connection with the sale of the MAN assets at June 30, 2004.

Management is also pursuing the disposal of SPC’s Long Haul Assets as part of a settlement with Touch America and Sierra Touch America (“STA”) in their bankruptcy proceeding. The settlement stipulates that SPC will pay $10 million to STA and transfer to STA substantially all of the Long Haul Assets consisting of three ducts plus SPC’s portion of fiber in the main cable. Upon this payment and after satisfaction of other obligations, all amounts remaining due on the $35 million promissory note ($17.5 million as of June 30, 2004) issued by SPC to STA shall be deemed paid and satisfied. The settlement also gives SPC title of one remaining duct, which SPC has contracted to sell. SPC recognized an impairment, in June 2004, of approximately $4.8 million (pretax) in connection with the anticipated sale of the Long Haul Assets. The settlement between STA and the holders of various mechanic liens that were filed against STA and SPC is expected to be finalized within one year. To the extent the final sales price differs from our estimate, an additional adjustment will be made accordingly.

SPR is filing the selected financial data for the five years ended December 31, 2003, consolidated financial statements as of December 31, 2003 and 2002 and for the three years ended December 31, 2003, the consolidated valuation and qualifying accounts and ratios of earnings to fixed charges in order to report the impact of our classification of SPC’s MAN Assets and Long Haul Assets, 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”).

Item 7. Financial Statements and Exhibits

(a) Financial Statements of Businesses Acquired

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.


	Year ended December 31,
	(dollars in thousands; except per share amounts)
	2003⁽³⁾			2002⁽²⁾			2001⁽¹⁾		2000			1999
Operating Revenues	$	2,787,543		$	2,984,604		$	4,574,987	$	2,325,066		$	1,279,061

Operating Income (Loss)	$	271,464		$	(27,509	)	$	224,641	$	126,674		$	162,395

Income (Loss) from Continuing Operations	$	(104,160	)	$	(294,979	)	$	35,818	$	(45,264	)	$	50,091

Earnings (Loss) from Continuing Operations Per Average Common Share - Basic	$	(.90	)	$	(2.89	)	$	0.41	$	(0.58	)	$	0.80

Earnings (Loss) from Continuing Operations Per Average Common Share - Diluted	$	(.90	)	$	(2.89	)	$	0.41	$	(0.58	)	$	0.80

Total Assets	$	7,063,758		$	7,110,639		$	8,132,727	$	5,804,251		$	5,348,659

Long-Term Debt	$	3,579,674		$	3,226,281		$	3,570,750	$	2,378,312		$	1,801,260

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

(1)		In 2001, the Utilities implemented deferred energy accounting for fuel and purchased power costs. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the 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. For the year ended 2001, fuel and purchase power costs were higher than normal due to the Western Energy Crisis, as a result, total Assets increased significantly from the year 2000 to 2001. Additionally, Operating Revenues were significantly higher in 2001 compared to other years due to volumes of wholesale electric power to other utilities and hedging activity.

(2)		Loss from Continuing Operations and Total Assets for the year ended December 31, 2002 was severely affected by the write-off of deferred energy costs and related carrying charges of $523 million as a result of the PUCN decision in NPC’s and SPPC’s deferred energy cases disallowing $434 million and $53 million, respectively, of deferred purchased fuel and power costs. See Major Factors Affecting Results of Operations, included in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion.

(3)		Loss from Continuing Operations for the year ended 2003 was negatively affected by an unrealized net loss of $46.1 million on the derivative instrument associated with the issuance of SPR’s $300 million Convertible Notes, $46 million and $45 million write-of of deferred energy costs by NPC and SPPC, respectively, the impairment of SPC of $32.9 million and approximately $52 million of interest charges related to the Enron Litigation.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2003 and 2002, 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, 2003. Our audits also included Schedule II, Consolidated Valuation and Qualifying Accounts. 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 standards of the Public Company Accounting Oversight Board (United States). 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 included 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, 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 1 to the consolidated financial statements, during 2002 the Company changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142, “Accounting for Goodwill.”

As discussed in Note 1 to the consolidated financial statements, during 2003 the Company changed the classification of asset removal costs as a result of the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

/s/ Deloitte & Touche LLP

Reno, Nevada
March 7, 2004
(August 6, 2004 as to the adoption of a new accounting standard as described in Note 18 — Earnings Per Share, and effects of the discontinued operations described in Note 19 — SPC Sale of Assets)

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


	December 31,
	2003 Balance		2002 Balance
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,353,399	$	5,989,701
Less accumulated provision for depreciation		1,953,271		1,792,700

		4,400,128		4,197,001
Construction work-in-progress		242,522		263,346

		4,642,650		4,460,347

Investments and other property, net		73,130		62,069

Current Assets:
Cash and cash equivalents		181,757		192,170
Restricted cash (Note 1)		54,705		13,705
Accounts receivable less provision for uncollectible accounts:
2003-$44,917; 2002-$44,184		301,322		358,593
Deferred energy costs - electric		295,677		268,979
Deferred energy costs - gas		1,358		17,045
Materials, supplies and fuel, at average cost		79,525		85,802
Risk management assets (Note 11)		22,099		29,570
Deposits and prepayments for energy		63,847		17,194
Other		33,016		30,527

		1,033,306		1,013,585

Deferred Charges and Other Assets:
Goodwill (Note 1)		309,971		309,971
Deferred energy costs - electric		497,905		685,875
Regulatory tax asset		155,547		163,889
Other regulatory assets (Note 1)		142,507		136,933
Risk management regulatory assets - net (Note 11)		14,283		44,970
Unamortized debt issuance expense		50,842		49,804
Other		103,545		98,973

		1,274,600		1,490,415
Assets of Discontinued Operations (Note 19)		40,072		84,223

	$	7,063,758	$	7,110,639

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	1,435,394	$	1,327,166
Preferred stock		50,000		50,000
Long-term debt		3,579,674		3,226,281

		5,065,068		4,603,447

Current Liabilities:
Short-term borrowings		25,000		-
Current maturities of long-term debt		218,970		672,895
Accounts payable		165,936		232,033
Accrued interest		59,592		44,114
Dividends declared		1,046		1,045
Accrued salaries and benefits		24,444		20,760
Deferred taxes		133,844		123,507
Risk management liabilities (Note 11)		16,540		69,953
Contract termination liabilities (Note 15)		338,704		-
Other current liabilities		37,087		36,710

		1,021,163		1,201,017

Commitments & Contingencies (Note 15)
Deferred Credits and Other Liabilities:
Deferred federal income taxes		271,091		336,875
Deferred investment tax credit		45,329		48,492
Regulatory tax liability		41,877		42,718
Customer advances for construction		126,506		116,032
Accrued retirement benefits		112,075		163,752
Risk management liabilities (Note 11)		-		3,917
Contract termination liabilities (Note 15)		45,766		318,158
Regulatory liabilities (Note 1)		218,158		28,904
Accrued removal costs		-		151,651
Other		80,859		48,887

		941,661		1,259,386
Liabilities of Discontinued Operations (Note 19)		35,866		46,789

	$	7,063,758	$	7,110,639

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,
	2003			2002			2001
OPERATING REVENUES:
Electric	$	2,624,426		$	2,832,285		$	4,426,881
Gas		161,586			149,783			145,652
Other		1,531			2,536			2,454

		2,787,543			2,984,604			4,574,987

OPERATING EXPENSES:
Operation:
Purchased power		1,104,344			1,786,823			4,052,077
Fuel for power generation		521,412			453,436			728,619
Gas purchased for resale		111,675			91,961			136,534
Deferred energy costs disallowed		90,964			491,081			—
Deferral of energy costs — electric — net		97,893			(233,814	)		(1,136,148	)
Deferral of energy costs — gas — net		16,155			24,785			(23,170	)
Other		324,608			279,895			314,996
Maintenance		69,636			64,440			69,499
Depreciation and amortization		191,259			174,200			165,614
Taxes:
Income tax benefit		(57,008	)		(165,249	)		(652	)
Other than income		45,141			44,554			42,976

		2,516,079			3,012,113			4,350,345

OPERATING INCOME (LOSS)		271,464			(27,509	)		224,641
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,765			(36	)		474
Interest accrued on deferred energy		28,054			23,058			55,204
Other income		29,948			10,988			12,450
Other expense		(14,243	)		(18,365	)		(13,633	)
Income taxes		(12,801	)		(4,058	)		(14,870	)
Unrealized loss on derivative instrument (Note 11)		(46,065	)		—			—

		(9,342	)		11,587			39,625

Total Income (Loss) Before Interest Charges		262,122			(15,922	)		264,267
INTEREST CHARGES:
Long-term debt		293,482			248,852			207,358
Other		78,776			35,475			23,892
Allowance for borrowed funds used during construction		(5,976	)		(5,270	)		(2,801	)

		366,282			279,058			228,449

INCOME (LOSS) FROM CONTINUING OPERATIONS		(104,160	)		(294,979	)		35,818
DISCONTINUED OPERATIONS:
Gain (loss) from discontinued operations (net of income taxes (benefits) of $(17,036), $(3,249), and $18,547 respectively)		(32,469	)		(7,076	)		24,615
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, net of tax (Note 1)		—			(1,566	)		—
NET INCOME (LOSS)		(136,629	)		(303,621	)		60,433
Preferred stock dividend requirements of subsidiary		3,900			3,900			3,700

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK	$	(140,529	)	$	(307,521	)	$	56,733

Amount per share — basic and diluted
Income / (Loss) from continuing operations	$	(0.90	)	$	(2.89	)	$	0.41
Income / (Loss) per share applicable to common stock	$	(1.21	)	$	(3.01	)	$	0.65
Weighted Average Shares of Common Stock Outstanding		115,774,810			102,126,079			87,542,441

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

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


	Year ended December 31,
	2003			2002			2001
Common Stock:
Balance at Beginning of Year	$	102,177		$	102,111		$	78,475
Stock issuance/exchange and dividend reinvestment		15,059			66			23,636

Balance at end of year		117,236			102,177			102,111

Other Paid-In Capital:
Balance at Beginning of Year		1,599,024			1,598,634			1,295,221
Premium on issuance/exchange of common stock		99,192			—			330,050
Common Stock issuance costs		(1,184	)		—			(13,910	)
Purchase contract adjustment payment		—			—			(13,676	)
Value of derivative transferred to equity		118,143			—			—
CSIP, DRP, ESPP and other		27			390			949

Balance at End of Year		1,815,202			1,599,024			1,598,634

Retained Earnings (Deficit):
Balance at Beginning of Year		(326,524	)		1,577			(13,984	)
Income (loss) from continuing operations before preferred dividends		(104,160	)		(294,979	)		35,818
Gain (loss) from discontinued operations (before preferred dividend allocation of $200 in 2001), net of taxes		(32,469	)		(7,076	)		24,815
Cumulative effect of change in accounting principle, net of tax		—			(1,566	)		—
Preferred stock dividends declared		(3,900	)		(3,900	)		(3,900	)
Common stock dividends declared, net of adjustments		370			(20,580	)		(41,172	)

Balance at End of Year		(466,683	)		(326,524	)		1,577

Accumulated Other Comprehensive Income (Loss):
Balance at Beginning of Year		(47,511	)		(6,986	)		—
Adoption of SFAS No. 133—Accounting for Derivative Instruments and Hedging Activities
Cumulative effect upon adoption of change in accounting principle as of January 1 (Net of income taxes of $1,035)		—			—			(1,923	)
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes (benefits) of $884, $3,083 and ($2,726) in 2003, 2002 and 2001, respectively)		1,642			5,726			(5,063	)
Minimum pension liability adjustment (Net of income taxes (benefits) of $8,698 and ($24,904) in 2003, and 2002, respectively)		15,508			(46,251	)		—

Balance at End of Year		(30,361	)		(47,511	)		(6,986	)

Total Common Shareholders’ Equity at End of Year	$	1,435,394		$	1,327,166		$	1,695,336

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

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


	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	(136,629	)	$	(303,621	)	$	60,433
Preferred dividends included in discontinued operations		—			—			200
Non-cash items included in income (loss):
Depreciation and amortization		191,940			175,218			169,289
Deferred taxes and deferred investment tax credit		(50,724	)		(169,714	)		85,917
AFUDC		(11,741	)		(5,234	)		(3,285	)
Amortization of deferred energy costs — electric		250,134			176,718			—
Amortization of deferred energy costs — gas		13,095			13,231			3,562
Deferred energy costs disallowed		90,964			493,053			—
Early retirement and severance amortization		2,786			2,706			3,121
Unrealized loss on derivative instrument		46,065			—			—
Impairment of assets of discontinued operations		32,911			—			—
Loss (gain) on disposal of discontinued operations		9,555			—			(44,082	)
Other non-cash		(12,489	)		5,818			2,863
Adjustment in value of Premium Income Equity Securities		—			—			(13,677	)
Changes in certain assets and liabilities:
Accounts receivable		57,271			30,560			6,471
Deferral of energy costs — electric		(179,826	)		(434,279	)		(1,187,840	)
Deferral of energy costs — gas		2,592			10,270			(30,245	)
Materials, supplies and fuel		6,277			5,317			(15,651	)
Other current assets		(49,142	)		(33,959	)		4,535
Accounts payable		(66,097	)		(23,707	)		(103,247	)
Income tax receivable		—			185,011			—
Other current liabilities		358,213			16,413			14,116
Change in net assets of discontinued operations		(11,727	)		667			(31,373	)
Other assets		47,348			(13,764	)		1,373
Other liabilities		(334,889	)		320,253			18,302

Net Cash from Operating Activities		255,887			450,957			(1,059,218	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(373,961	)		(399,807	)		(333,606	)
AFUDC and other charges to utility plant		11,741			5,234			3,285
Customer advances for construction		10,475			7,852			815
Contributions in aid of construction		23,605			43,247			27,481

Net cash used for utility plant		(328,140	)		(343,474	)		(302,025	)
Proceeds from sale of assets of water business		—			—			318,882
Investments in subsidiaries and other property — net		(9,120	)		(5,538	)		(4,261	)

Net Cash from Investing Activities		(337,260	)		(349,012	)		12,596

CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings		25,000			(177,000	)		(36,074	)
Restricted cash		(41,000	)		(13,705	)		—
Proceeds from issuance of long-term debt		650,000			350,000			1,225,503
Retirement of long-term debt		(558,760	)		(143,584	)		(323,091	)
Redemption of preferred stock		—			—			(48,500	)
Sale of common stock, net of issuance cost		(756	)		460			340,737
Dividends paid		(3,524	)		(24,485	)		(64,917	)

Net Cash from Financing Activities		70,960			(8,314	)		1,093,658

Net Increase (decrease) in Cash and Cash Equivalents		(10,413	)		93,631			47,036
Beginning Balance in Cash and Cash Equivalents		192,170			98,539			51,503

Ending Balance in Cash and Cash Equivalents	$	181,757		$	192,170		$	98,539

Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during period for:
Interest	$	307,870		$	257,462		$	208,390
Income taxes	$	(1,521	)	$	(185,011	)	$	(55,022	)
Noncash financing activities (Note 8):
Exchanged Floating Rate Notes for SPR common stock	$	8,750		$	—		$	—
Exchanged Premium Income Equity Securities for SPR common stock	$	104,782		$	—		$	—

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

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


	December 31,
	2003			2002
Common Shareholders’ Equity:
Common stock $1.00 par value, authorized 250 million; issued and outstanding 2002: 102,177,000 shares; 2001: 102,111,000 shares	$	117,236		$	102,177
Other paid-in capital		1,815,202			1,599,024
Retained earnings (deficit)		(466,683	)		(326,524	)
Accumulated Other Comprehensive Loss		(30,361	)		(47,511	)

Total Common Shareholders’ Equity		1,435,394			1,327,166

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

Long-Term Debt:
Unamortized bond premium and discount, net		(21,750	)		(17,968	)

8.2% Junior Subordinated Debentures of NVP, due 2037		122,548			122,548
7.75% Junior Subordinated Debentures of NVP, due 2038		72,165			72,165

Subtotal		194,713			194,713

Debt Secured by First Mortgage Bonds
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
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 MTN due 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
6.70% Series II due 2032		21,200			21,200
5.50% Series D MTN due 2003		—			5,000
5.59% Series D MTN due 2003		—			13,000

Subtotal, excluding current portion		744,750			762,750

(Continued)

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

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


	December 31,
	2003			2002
Continued from previous page
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

Subtotal		258,035			258,035

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
IDRB Series 2000A due 2020		100,000			100,000
PCRB Series 2000B due 2009		15,000			15,000
Floating Rate Notes due 2003		—			200,000

Subtotal		115,000			455,000

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			250,000
9.00% Series G due 2019		350,000			—
8.00% Series A due 2008		320,000			320,000
10.50% (Variable) Series C due 2005		99,000			100,000
6.20% Series 1999B due 2004		130,000			130,000

Subtotal		1,499,000			1,150,000

Other Notes:
7.50% Series 2001 due 2036		80,000			80,000
6.00% Series B notes due 2003		—			210,000
8.75% Senior unsecured note Series 2000 due 2005		300,000			300,000
7.93% Senior unsecured notes due 2007		240,218
7.25% Convertible notes due 2010		234,118			345,000

Subtotal		854,336			935,000

Obligations under capital leases		68,587			73,259

Current maturities and sinking fund requirements		(218,970	)		(672,963	)

Other		12,673			15,155

Total Long-Term Debt		3,579,674			3,226,281

TOTAL CAPITALIZATION	$	5,065,068		$	4,603,447

(Concluded)

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:

Basis of Presentation

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). Certain business segments of e ·three and SPC are discontinued operations and as such are 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.

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.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 60% of the consolidated assets of SPR at December 31, 2003. NPC provides electricity to approximately 703,000 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 NPC’s wholly-owned subsidiary, Nevada Electric Investment Company (NEICO).

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 33% of the consolidated assets of SPR at December 31, 2003. SPPC provides electricity to approximately 334,000 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. SPPC also provides natural gas service in Nevada to approximately 129,000 customers in an area of about 600 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC 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. SPC was formed in 1999 to provide telecommunications services using fiber optic cable technology in both northern and southern Nevada.

Reclassifications

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

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are currently subject to the approval of the Public Utilities Commission of Nevada (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 deferral 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) regulated rates are designed to recover the specific costs of the regulated products or services; and (iii) it is reasonable to assume that rates are set at levels that recovered 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.

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 could 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):

SIERRA PACIFIC RESOURCES
OTHER REGULATORY ASSETS AND LIABILITIES


		Receiving Regulatory Treatment
						Pending
	Remaining	Earning a		Not Earning		Regulatory			2003		2002
DESCRIPTION	Amortization Period	Return(1)(2)		a Return		Treatment			Total		Total
Regulatory Assets
Early retirement and severance offers	Various through 2004	$	—	$	2,497	$	—		$	2,497	$	4,995
Loss on reacquired debt	Various		30,123		—		—			30,123		31,812
Plant assets	Various through 2031		3,414		—		—			3,414		3,558
Nevada divestiture costs			—		—		35,164	(2)		35,164		32,313
Merger transition costs			—		—		14,185			14,185		12,601
Merger severance/relocation			—		—		21,375			21,375		21,747
Merger goodwill			—		—		19,070			19,070		19,675
California restructure costs	Through 2008		2,448		—		1,920			4,368		4,318
Conservation programs			—		—		8,361			8,361		3,374
Variable rate mechanism deferral	Through 10/04		—		352					352		721
Other costs			—		—		3,598			3,598		1,819

Total other regulatory assets		$	35,985	$	2,849	$	103,673		$	142,507	$	136,933

Regulatory Liabilities
Cost of Removal		$	174,717	$	—	$	—		$	174,717	$	—
Gain on Property Sales	Various through 2006		16,430		900		21,982			39,312		2,341
SO2 Allowances	Various through 2006		4,129		—		—			4,129		7,313
Deferred Fuel Over-Collection												19,250

Total regulatory liabilities		$	195,276	$	900	$	21,982		$	218,158	$	28,904

NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


		Receiving Regulatory Treatment
						Pending
	Remaining	Earning a		Not Earning		Regulatory			2003		2002
DESCRIPTION	Amortization Period	Return(1)(2)		a Return		Treatment			Total		Total
Loss on reacquired debt	Various	$	13,956	$	—	$	—		$	13,956	$	14,778
Nevada divestiture costs			—		—		21,886	(2)		21,886		20,134
Merger transition costs			—		—		7,652			7,652		5,328
Merger severance/relocation			—		—		10,209			10,209		10,199
Conservation programs			—		—		6,809			6,809		2,478
Other costs			—		—		209			209		192

Total other regulatory assets		$	13,956	$	—	$	46,765		$	60,721	$	53,109

Regulatory Liabilities
Cost of Removal		$	104,446	$	—	$	—		$	104,446	$	—
Gain on Property Sales	Various through 2006		16,430		900		21,982			39,312		2,341
SO2 Allowances	Various through 2006		4,129		—		—			4,129		7,313
Deferred Fuel Over-Collection												19,250

Total regulatory liabilities		$	125,005	$	900	$	21,982		$	147,887	$	28,904

SIERRA PACIFIC POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


		Receiving Regulatory Treatment
	Remaining					Pending
	Amortization	Earning a		Not Earning		Regulatory			2003		2002
DESCRIPTION	Period	Return(1)(2)		a Return		Treatment			Total		Total
Early retirement and severance offers	Various through 2004	$	—	$	2,497	$	—		$	2,497	$	4,995
Loss on reacquired debt	Various		16,167		—		—			16,167		17,034
Plant assets	Various through 2031		3,414		—		—			3,414		3,558
Nevada divestiture costs			—		—		13,278	(2)		13,278		12,179
Merger transition costs			—		—		6,533			6,533		7,273
Merger severance/relocation			—		—		11,166			11,166		11,548
California Restructure Costs	Through 2008		2,448		—		1,920			4,368		4,318
Conservation Programs	Various through 2007		—		—		1,552			1,552		896
Variable rate mechanism deferral	Through 10/04		—		352		—			352		721
Other costs			—		—		3,389			3,389		1,627

Total other regulatory assets		$	22,029	$	2,849	$	37,838		$	62,716	$	64,149

Regulatory Liabilities
Cost of Removal		$	70,271	$	—	$	—		$	70,271	$	—

(1)		Regulatory liabilities included in this column are treated as reductions to rate base, on which a rate of return is earned.

(2)		Regulatory asset is currently earning a return.

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 on customers of fluctuations in the cost of purchased gas, fuel, and purchased power.

In January 2000, in accordance with a PUCN order SPPC resumed using deferred energy accounting for its gas operations.

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

result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances.

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


	December 31, 2003
	NPC		SPPC		SPPC		SPR
Description	Electric		Electric		Gas		Total
Unamortized balances approved for collection in current rates	$	274,164	$	45,039	$	941	$	320,144
Balances pending PUCN approval		91,323		42,398		—		133,721
Balances accrued since end of periods submitted for PUCN approval		8,477		3,559		417		12,453
Terminated supply contracts (2)		244,590		84,032		—		328,622

Total	$	618,554	$	175,028	$	1,358	$	794,940

Current Assets
Deferred energy costs—electric	$	247,249	$	48,428	$	—	$	295,677
Deferred energy costs—gas		—		—		1,358		1,358
Deferred Assets
Deferred energy costs—electric		371,305		126,600		—		497,905

Total	$	618,554	$	175,028	$	1,358	$	794,940


	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 supply contracts (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

(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 claims for terminated supply contracts are discussed in Note 15, of Notes to Financial Statements, 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 other 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, post retirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC).

Allowance For Funds Used During Construction

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 2003, 2002 and 2001 were 8.37%, 4.72%, and 8.32%, respectively. SPPC’s AFUDC rates used during 2003, 2002 and 2001 were 8.61%, 5.54%, and 7.97%, 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 2003, 2002 and 2001, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.06%, 3.0%, and 2.94%, respectively. SPPC’s depreciation provision for 2003, 2002 and 2001, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.31%, 3.33%, and 3.29%, respectively.

Impairment of Long-Lived Assets

SPR, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in SFAS No. 144 “Accounting for the Disposal or Impairment of Long-Lived Assets.” See Note 19 of Notes to Financial Statements, Discontinued Operations and Disposal and Impairment of Long-Lived Assets.

Accounting For Goodwill

SFAS No. 142 “Goodwill and Other Intangible Assets”, 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. In the year ended 2002, upon adoption, SPR ceased amortizing goodwill and recorded a cumulative effect of change in accounting principle, net of tax, of $1.6 million, due to an impairment associated with SPR’s unregulated subsidiaries.

SPR’s Consolidated Balance Sheet as of December 31, 2003, includes approximately $325 million of goodwill pertaining to regulated operations resulting from the July 28, 1999 merger between SPR and NPC. 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 filed by NPC and SPPC on October 1, 2003 and December 1, 2003, respectively. The decisions on these cases are expected in the spring of 2004. For further discussion, see Note 15, of Notes to Financial Statements, Commitments and Contingencies, Regulatory.

On January 1, 2003, SPR reviewed goodwill of the unregulated subsidiaries for impairment. As of January 1, 2003, SPR recorded an additional $470,000 to operating expense for impairment of goodwill. As of December 31, 2003, goodwill related to the unregulated subsidiaries, included in SPR’s Consolidated Balance Sheet, is approximately $4.0 million.

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.

Restricted Cash

At December 31, 2003 and 2002, SPR had approximately $55 million and $14 million, respectively of restricted cash in SPR’s consolidated balance sheets, primarily all of which is restricted for debt service payments for the $300 million convertible notes, discussed in Note 8, Long-Term Debt and the remaining amount consists mainly of cash balances that are required to be maintained by financial institutions due to the financial condition of SPR, NPC and SPPC.

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. 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 basics 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.

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

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. Accounts receivable as of December 31, 2003, include unbilled receivables of $63 million and $56 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2002, include unbilled receivables of $60 million and $63 million for NPC and SPPC, respectively. Accounts receivable, affiliate companies is comprised mainly of amounts owed as a result of tax sharing agreements.

Stock Compensation Plans

At December 31, 2003, SPR had several stock-based compensation plans, which are described more fully in Note 14 of Notes to Financial Statements, Stock Compensation Plans. SPR applies Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” in accounting for its stock option plans and in accordance with the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and the updated disclosure requirements set forth in SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. Had compensation cost for SPR’s nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans, consistent with the accounting provisions of SFAS No. 123, SPR’s Earnings (Loss) applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except per share amounts):


		2003			2002			2001
Earnings (Loss) applicable to Common Stock, as reported		$	(140,529	)	$	(307,521	)	$	56,733
Add: Stock (Loss) Compensation Cost included in net income as reported, net of related tax effects			410			(1,567	)		346
Less: Pro Forma Stock Compensation Cost, net of related tax effects			(1,750	)		(480	)		(1,555	)

Pro Forma Earnings (Loss) applicable to Common Stock		$	(141,869	)	$	(309,568	)	$	55,524

Basic Earnings (Loss) Per Share	As Reported	$	(1.21	)	$	(3.01	)	$	0.65
	Pro Forma	$	(1.22	)	$	(3.03	)	$	0.63
Diluted Earnings (Loss) Per Share	As Reported	$	(1.21	)	$	(3.01	)	$	0.65
	Pro Forma	$	(1.22	)	$	(3.03	)	$	0.63

Asset Retirement Obligations

SFAS No. 143 “Accounting for Asset Retirement Obligations” 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. SPR, NPC and SPPC adopted SFAS No. 143 on January 1, 2003.

Management’s methodology to assess its legal obligation included an inventory of assets by system and components and a review of rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. 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. In determining its Asset Retirement Obligations, management assumes that transmission, distribution and communications systems will be operated in perpetuity and will continue to be used or sold without land remediation and that mass asset properties that are replaced or retired frequently will be considered normal maintenance. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems.

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 did not have a material effect on the financial position or results of operations of SPR or NPC. SPPC has no significant asset retirement obligations.

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.

In addition to the asset retirement obligations the Utilities have accrued for the cost of removing other electric and gas assets through its depreciation rates, in accordance with accepted regulatory practices. The accrual was previously included in accumulated depreciation but is currently reflected as regulatory liabilities, as of December 31, 2003 and as accrued cost of removal as of December 31, 2002. The amount of such accruals included in regulatory liabilities in 2003 of approximately $104 million and $70 million for NPC and SPPC, respectively. Approximately $92 million and $59 million for NPC and SPPC respectively, based on the cost of removal component in current depreciation rates.

Recent Pronouncements

In December 2003, the FASB issued Interpretation No. 46, revised December 2003 “Consolidation of Variable Interest Entities” (FIN 46(R)), which elaborates on Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” Among other requirements, FIN 46(R) provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. As of December 31, 2003, we have adopted FIN 46(R) for special purpose entities. Management believes that NPC’s Trust I and Trust III subsidiaries (Preferred Trust Securities) are variable interest entities but management believes that NPC is not the primary beneficiary, as such, under the provisions of FIN 46(R), NPC is required to deconsolidate. FIN 46(R) encourages restatement of prior periods, as such all periods presented have been restated to reflect the deconsolidation of NPC’s Preferred Trust Securities. As a result, the Preferred Trust Securities previously reported in Long-Term Debt upon consolidation, are no longer reported and NPC’s Junior Subordinated Debt, which was previously eliminated upon consolidation, is now reported as Long-Term Debt. Additionally, the $5.8 million equity investment NPC had in the Trusts is recorded as Investments in Subsidiaries and Other Property and Long-Term Debt for all periods presented. The $5.8 million represents NPC’s maximum exposure to loss as a result of its involvement with the variable interest entity. The deconsolidation did not have an effect on the results of operations for SPR or NPC, except that Dividend requirements of NPC’s Obligated Mandatorily Redeemable Preferred Trust Securities have been reclassified to Interest Charges – Long-Term Debt for all periods presented. See Note 8 of Notes to Financial Statements, Long-Term Debt for a description of the Preferred Trust Securities.

Management has identified certain relationships such as, joint and shared facilities and agreements with other power suppliers, that we may have a variable interest in or be the primary beneficiary for which the provisions of FIN 46(R) would apply. At this time management is unable to determine if (1) we will be required to consolidate the various entities, or (2) the financial impact on SPR’s, NPC’s or SPPC’s financial position, or results of operations will be material. FIN 46(R) requires that SPR, NPC and SPPC apply this interpretation to all entities subject to this interpretation by March 31, 2004.

On April 30, 2003, the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, which amends accounting for derivative instruments, including certain derivative instruments embedded in other

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

On May 15, 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” which requires that certain financial instruments with characteristics of both liabilities and equities be classified as liabilities by their issuers. The provisions of SFAS No. 150, which also include a number of new disclosure requirements, are effective for (1) instruments entered into or modified after May 31, 2003 and (2) pre-existing instruments as of the beginning of the first interim period that commences after June 15, 2003. At December 31, 2003, the adoption of SFAS No. 150 did not have an effect on the financial position, results of operations or cash flows for SPR, NPC and SPPC.

In December 2003, the FASB revised SFAS No. 132 “Employers’ Disclosures about Pensions and Other Postretirement Benefits” which revises employers’ disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” This statement requires additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. SPR, NPC and SPPC adopted the revised standard as of December 31, 2003. See Note 13 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits.

In December 2003, the FASB issued FASB Staff Position No. 106-1 (FSP No. 106-1), in response to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) signed into law in December 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Paragraph 40 of SFAS No. 106 “Employers Accounting for Postretirement Benefits Other Than Pensions” requires presently enacted changes in relevant laws to be considered in current period measurements of postretirement benefit costs and the Accumulated Pension Benefit Obligation (APBO). Therefore, under that guidance, measures of the APBO and net periodic postretirement benefit costs on or after the date of enactment should reflect the effects of the Act. However, due to several uncertainties of the Act, under FSP No. 106-1 SPR is permitted to defer recognizing the effects of the Act in the accounting for its plan under Statement 106 and in providing disclosures related to the plan required by SFAS No. 132 (revised 2003), until authoritative guidance on the accounting for the federal subsidy is issued. SPR, NPC and SPPC have elected to defer implementation. As such, any measures of the APBO or net periodic postretirement benefit cost in the consolidated financial statements and notes to consolidated financial statements for SPR, NPC and SPPC do not reflect the effects of the Act on the plan. Future authoritative guidance on accounting for the subsidy may require changes to previously reported information. Management is unable to determine the financial impact of the Act on the financial position, results of operations or cash flows for SPR, NPC or SPPC at this time.

NOTE 2. LIQUIDITY MATTERS AND MANAGEMENT’S PLANS

Background

During 2002, the Utilities were severely affected by increased wholesale prices and the related regulatory decisions that denied the Utilities the ability to fully recover incurred fuel and purchased power costs. During the year ended December 31, 2000, and continuing into the first quarter of 2001, the Utilities experienced volatile and unprecedented fuel and purchased power prices. In order to assure adequate supplies of electricity for their customers, the Utilities incurred fuel and purchased power costs in excess of amounts they were permitted to recover in rates. Throughout the year ended December 31, 2000, because the Utilities’ allowed recovery was not keeping pace with the cost of providing service, the Utilities sought to adjust their rates to reflect their increased costs. Despite the Utilities’ efforts, fuel and purchased power costs continued to escalate and rate recovery could not keep up with the cost of fuel and purchased power. Accordingly, further relief was sought pursuant to legislation and in April 2001, the Governor of Nevada signed into law Assembly Bill 369 (AB 369).

Among other things, AB 369 reinstated deferred energy accounting for electric utilities beginning March 1, 2001. One of the primary objectives of this emergency legislation was to ease the effect of the fluctuations in the price of electricity in the retail market in Nevada and to ensure that the Utilities had the necessary financial resources to provide adequate and reliable electric service under the then present market conditions.

By September 30, 2001, the end of the first period for which a deferred energy application was required to be filed for NPC, NPC had accumulated approximately $922 million of unrecovered fuel and purchased power costs. Similarly, by November 30, 2001,

the end of the first period for which SPPC could request recovery of accumulated deferred fuel and purchase power costs, SPPC had incurred approximately $205 million of such costs. On March 29, 2002, the PUCN disallowed recovery of approximately $434 million of costs included in the request filed by NPC. As a result of this disallowance, NPC wrote off approximately $465 million of deferred energy costs and related carrying charges. The two major national rating agencies immediately downgraded the credit ratings of SPR’s, NPC’s and SPPC’s debt securities (followed by further downgrades in late April 2002), and the market price of SPR’s common stock fell substantially. In addition, the May 28, 2002 decision of the PUCN in SPPC’s deferred energy rate case, disallowed recovery of $53 million of incurred deferred fuel and purchased power costs.

These events resulted in the termination of the Utilities’ commercial paper programs, their unsecured revolving credit facilities as well as the termination of several fuel and power sales contracts by significant suppliers. As of December 31, 2003, asserted claims and judgments for liquidated damages in connection with the terminated contracts (excluding interest) were approximately $385 million. See discussion of the related Enron litigation below. Presently, in order to purchase power and transact with suppliers, NPC and SPPC are generally required to post collateral, prepay or at a minimum, remit payments within a very short period of time. As evidenced by financing transactions consummated in 2003, access to the capital markets to raise funds has been limited, interest rates charged by the market for debt have been higher and accordingly, debt service requirements of SPR, NPC and SPPC have increased.

Because of long-term purchased power contracts entered into during 2001, both Utilities continued to record additional amounts in their deferral of energy costs accounts during 2002. NPC and SPPC filed the required requests for recovery of these and other deferred fuel and purchased power costs in November 2002 and January 2003, respectively. NPC’s application requested recovery of approximately $196 million of deferred costs and SPPC’s application sought to recover approximately $15 million of such costs. The decisions in these cases were issued in May 2003 and resulted in further disallowances of approximately $46 million at NPC and an approximate reduction of accumulated deferred costs of $45 million (leaving a balance payable to customers of approximately $30 million) at SPPC.

Significant Uncertainties

As a result of the matters discussed above as well as other matters related to their business operations, the financial statements of SPR, NPC and SPPC are subject to significant uncertainties. Management believes that the most significant uncertainties facing SPR and the Utilities in 2004 are:

• whether there will be any further requirements to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron or to provide further cash collateral, to secure the stay of the judgment against the Utilities pending further appeal,

• whether the Utilities will be able to recover regulatory assets in their current and future rate cases, especially previously incurred deferred fuel and purchased power costs, and to provide sufficient revenues to support their operations,

• whether the Utilities will have sufficient liquidity and the ability in light of certain restrictions to provide dividends to SPR, and

• whether SPR and the Utilities will be able to successfully refinance maturing long-term debt and secure additional liquidity necessary to support their operations, including the purchase of fuel and power.

These uncertainties and management’s plans with respect to these matters are discussed in more detail below.

Because of the relationships among the uncertainties described above, an adverse development with respect to a combination of these uncertainties, could have a material adverse effect on SPR’s, NPC’s and SPPC’s financial condition, results of operations and liquidity, and could make it difficult for them to continue to operate outside of bankruptcy.

Enron Litigation

As further discussed in Note 15, Commitments and Contingencies, in June 2002, Enron Power Marketing, Inc. (Enron) filed a complaint with the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”) against NPC and SPPC seeking to recover liquidated damages for power supply contracts terminated by Enron in May 2002. On September 26, 2003, the Bankruptcy Court entered a judgment (the “Judgment”) in favor of Enron for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment requires NPC and SPPC to pay approximately $235 million and $103 million, respectively, to Enron for liquidated damages and pre-judgment interest for power not delivered by Enron.

In response to the Judgment, the Utilities filed a motion with the Bankruptcy Court seeking a stay pending appeal of the Judgment and proposing to issue General and Refunding Mortgage Bonds as collateral to secure payment of the Judgment. On November 6, 2003, the Bankruptcy Court ruled to stay execution of the Judgment conditioned upon NPC and SPPC posting into escrow $235 million and $103 million, respectively, of General and Refunding Mortgage Bonds plus $281,695 in cash by NPC for prejudgment interest. On December 4, 2003, NPC and SPPC complied with the order of the Bankruptcy Court by issuing their $235 million General and Refunding Mortgage Bond, Series H and $103 million General and Refunding Mortgage Bond, Series E, respectively, into escrow along with the required cash deposits for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which lowered the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. NPC and SPPC made the payments as ordered on February 10, 2004. The Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall seek a ruling from the PUCN to determine whether the cash payments into escrow trigger the Utilities’ rights to seek recovery of such amounts through their deferred energy rate cases. Furthermore, hearings have been scheduled for March 24, 2004, in front of the Bankruptcy Court to review the Utilities’ abilities to provide additional cash collateral which, if required, would reduce the principal amount of the General and Refunding Mortgage Bonds held in escrow by a like amount.

It is presently unknown as to whether there will be any further requirement to pay the Judgment or to provide further cash collateral to secure the stay of the judgment against the Utilities pending further appeal. Further, it is uncertain how the court will rule in the pending appeal of the Judgment and if there is an adverse decision in the appeal, whether the Judgment would continue to be stayed pending further appeal.

Liquidity and Financing Matters

NPC anticipates capital requirements for construction costs in 2004 will be approximately $381 million which NPC expects to finance with internally generated funds, including the recovery of deferred energy costs. NPC has $130 million of long-term debt maturing on April 15, 2004. NPC currently expects to refinance all of this debt prior to maturity through the issuance and sale of its General and Refunding Mortgage Securities.

SPPC anticipates capital requirements for construction costs during 2004 totaling approximately $107 million, which SPPC expects to finance with internally generated funds, including the recovery of deferred energy costs. SPPC has $80 million of long-term debt that it will be required to remarket or purchase by May 3, 2004.

Due primarily to the Utilities’ weakened financial conditions, the Utilities have been required to pre-pay their power purchases or make more frequent payments for power deliveries. As a result of unseasonably cool weather during the spring of 2003 and its prepayment and more frequent payment obligations for its summer 2003 power requirements, NPC’s liquidity was significantly constrained during the early summer months of 2003. Consequently, on June 30, 2003, NPC entered into a $60 million revolving Credit Agreement to provide additional liquidity to NPC for its summer 2003 power purchases. An increase in natural gas prices during SPPC’s winter 2003-2004 peak season negatively impacted SPPC’s cash flows, which SPPC addressed by issuing and selling its short-term $25 million Series F General and Refunding Mortgage Notes due March 31, 2004. In addition, SPPC entered into a $22 million short-term revolving Credit Agreement which expires March 31, 2004 to provide it with back-up liquidity during this winter peak season.

NPC anticipates that based upon its current cash balances and expected cash flows leading up to the summer 2004 season, NPC may utilize its A/R facility at the onset of the summer 2004 season to support its power purchases. Currently, management believes that NPC will be able to enter into financings and/or credit facilities to meet its summer 2004 cash needs.

SPPC anticipates that based upon its current cash balance and expected cash flows leading up to the summer 2004 peak season, SPPC will not need additional liquidity to support its power and natural gas purchases. Currently, SPPC is exploring the possibility of taking advantage of favorable conditions in the capital markets by entering into new financings to refinance existing debt on more favorable terms and to provide for additional or replacement back-up liquidity facilities.

If the Utilities have to pay significantly higher than expected prices for fuel and purchased power, if their suppliers require significant changes to their current payment terms, or if they do not have sufficient available liquidity to obtain fuel, purchased power and, for SPPC, natural gas, the Utilities may be required to issue or incur additional indebtedness, enter into additional liquidity facilities or utilize their receivables purchase facilities. If they are unable to enter into financings to provide them with sufficient additional liquidity and to repay their maturing indebtedness, whether due to unfavorable conditions in the capital markets, lack of regulatory authority to issue or incur such debt, credit downgrades by either S&P or Moody’s resulting from the uncertainties discussed in this section, or restrictive covenants in certain of their financing agreements (See Note 7 - Short-Term Borrowings and

Note 8 Long-Term Debt), their ability to provide power and fund their expected construction costs and their financial conditions and cash flows will be adversely affected.

SPR does not have any operations of its own and relies on dividends from the Utilities in order to satisfy its debt service obligations. SPR has approximately $70 million of debt service obligations payable during 2004; $22 million, which relate to SPR’s 7.25% Convertible Notes due 2010, have been previously provided for through the pledge of U.S. government securities with the trustee at the time the Convertible Notes were issued. See Note 8, Long-Term Debt. Therefore, approximately $48 million of debt service requirements will need to be funded through dividends from the Utilities. Currently, SPR expects to meet its remaining interest obligations for 2004 through the payment of dividends by the Utilities to SPR. In the event that NPC or SPPC is unable to pay dividends to SPR, SPR’s liquidity and cash flows would be adversely impacted. See Note 10 — Dividend Restrictions for a discussion of the dividend restrictions applicable to the Utilities.

Regulatory Matters

As required, NPC filed its biennial General Rate Case on October 1, 2003. NPC has requested a $133 million increase in the revenue requirement for general rates Specifically, NPC requested that a $50 million (computed on an annual revenue basis) or 3.4% rate increase commence on April 1, 2004 and continue for nine months. Beginning January 1, 2005, annualized general revenue would then increase by $92 million plus the amount necessary to return $76 million (the estimated amount being deferred (plus interest) during the prior nine month period) over the following 15 months.

On November 14, 2003, NPC filed an application with the PUCN seeking recovery of fuel and purchased power costs accumulated between October 1, 2002 and September 30, 2003. The application sought to establish a rate to collect accumulated costs of $93 million, together with a carrying charge, over a period of not more than three years. The application also requested an increase to the going-forward rate for energy.

On December 1, 2003, SPPC filed an application with the PUCN seeking an electric general rate increase. In the 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 approximately $95 million. Similar to NPC, SPPC is also asking for a staggered implementation of the overall revenue requirement. If approved, SPPC would recover $70 million of the $95 million request in the first year beginning mid July 2004, delaying the other $25 million, plus a carrying charge, until the next year.

On January 14, 2004, SPPC filed an application with the PUCN seeking to clear approximately $42 million of deferred balances for fuel and purchased power costs accumulated between December 1, 2002, and November 30, 2003. The application requests an asymmetric amortization of the deferred energy balance that would result in recovery of $8 million in the first year, effective mid July 2004, and $17 million for each of the two years thereafter. The request for resetting the Base Tariff Energy Rate would result in no change to the currently effective rate.

Management believes that they have satisfied the requirements necessary to increase the general rates as requested and that further, fuel and purchased power costs have been prudently incurred; however, management cannot predict the outcome of these proceedings. Material disallowances of deferred energy costs or inadequate base rates would have a significant adverse effect on NPC’s and SPPC’s financial conditions and future results of operations, could cause additional downgrades of its securities by the rating agencies and make it more difficult to finance operations and to buy fuel and purchased power from third parties.

Management’s Plans

Enron Litigation

The Utilities are appealing the judgment of the Enron Bankruptcy Court to the U.S. District Court of the Southern District of New York. In addition, they continue to pursue their FERC Section 206 complaint against Enron. In the event the Utilities were to lose the pending appeal, management currently plans to file an appeal in the U.S. Court of Appeals for the Second Circuit and request that a stay be granted pending the second appeal. In connection with any subsequent appeal of the Judgment, the Utilities currently anticipate that they will assert that because of the full protection afforded Enron by the existing collateral, a further stay is warranted, without any material change to the collateral.

Although management believes that the stay of execution of the Judgment will be continued through the appeal process and no significant change will be made to the requirement to post cash collateral, management believes that through financial arrangements currently being negotiated, the Utilities would have the means to meet a substantial payment obligation on the Judgment.

The Utilities expect to enter into a Remarketing Agreement with Enron and one or more investment banks as Remarketing Agent(s) to provide for the remarketing of the Bonds which are presently held in escrow. Although the terms of such a remarketing

agreement are not final, management believes that the form of the final agreement will facilitate the successful remarketing of the Bonds to satisfy the Utilities’ payment obligations with respect to the Judgment. The Remarketing Agreement will allow Enron, at its option, to require the initiation of a remarketing process with respect to the Bonds and will contain certain provisions that will provide the Utilities with flexibility to modify the terms of the Bonds to attempt a successful initial remarketing effort at the lowest possible interest rate to be determined by the Remarketing Agent(s).

If the Utilities are unsuccessful in the remarketing of the Bonds or if Enron chooses not to have the Bonds remarketed, the Bonds would, from that point forward, accrue interest at 14% and mature in one year; however, Enron would have the right, at any time prior to maturity, to require that the Utilities redeem their bonds at par within four business days. Under the terms of the escrow arrangement between the Utilities and Enron, prior to taking possession of the Bonds, Enron would be required to release the Utilities from any and all payment obligations with respect to the Judgment.

If the appeal process is unsuccessful and the Judgment is ultimately paid, the Utilities plan to pursue recovery of the amounts paid through future deferred energy filings. Determination of the amount of recovery through rates, if any, will be made through the Utilities’ usual regulatory process. There is no assurance that the PUCN will allow recovery of any amounts ultimately paid to Enron.

Liquidity and Financing Matters

Based on current market conditions and the history of market access since the credit rating downgrades, management believes that they will be able to successfully refinance the $130 million of NPC’s 6.20% Series B, Senior Notes due 2004 maturing on April 15, 2004. Management also believes SPPC will be able to successfully remarket the $80 million of Water Facility Refunding Revenue Bonds prior to May 1, 2004. Management is also giving consideration to obtaining additional funding that would provide for certain amounts of working capital facilities as well as potentially refunding certain debt obligations due in 2005.

On January 21, 2004, NPC filed an application with the PUCN for authority to issue secured long-term debt in an aggregate amount not to exceed $230 million through the period ending December 31, 2004. This authority was requested to allow for the refinancing of the NPC’s $130 million 6.20% Series B Senior Notes due 2004, as well as to provide an additional $100 million of liquidity to support utility operations.

On October 9, 2003, NPC filed an application with the PUCN for authority to issue secured or unsecured short-term debt securities in an aggregate amount not to exceed $250 million through the period ending December 31, 2005. This authority was requested to replace the existing short-term debt authority that expired on December 31, 2003. On December 17, 2003, the PUCN issued an order granting NPC the authority to issue up to $250 million in short-term secured or unsecured debt securities. This authority expires December 31, 2005.

Currently, management believes that NPC will be able to enter into financings and/or credit facilities to meet its summer 2004 cash needs. Alternatively, NPC may draw on its accounts receivable facility for additional liquidity. Actual amounts that may be advanced under the receivables purchase facility will vary significantly depending upon, among other things, the time of year, the weather conditions and the delinquency notes of NPC’s receivables. Based on 2003 accounts receivables and the variables discussed above, NPC had a maximum capacity of $82 million and minimum capacity of $32 million under the receivables facility. If NPC does not have sufficient liquidity to meet its power requirements, particularly at the onset of the 2004 summer season, NPC may be required to issue or incur additional indebtedness.

On October 9, 2003, SPPC filed an application with the PUCN for authority to issue secured or unsecured short-term debt securities in an aggregate amount not to exceed $250 million through the period ending December 31, 2005. This authority was requested to replace the existing short-term debt authority that expired on December 31, 2003. On December 17, 2003, the PUCN issued an order granting SPPC the authority to issue up to $250 million in short-term secured or unsecured debt securities. This short-term debt authority will expire December 31, 2005.

On December 31, 2003, SPPC filed an application with the PUCN for authority to issue secured long-term debt in an aggregate amount not to exceed $230 million through the period ending December 31, 2004. This authority was requested to allow for the refinancing and remarketing of existing debt securities, as well as to provide additional liquidity to support utility operations.

Currently, management believes that SPPC will be able to internally generate sufficient cash to meets its power procurement cash needs. Alternatively, management believes that SPPC will be able to enter into financings and/or credit facilities or may draw on its accounts receivable facility for additional liquidity. Actual amounts that may be advanced under the receivables purchase facility will vary significantly depending upon, among other things, the time of year, the weather conditions and the delinquency notes of SPPC’s receivables. Based on 2003 accounts receivables and the variables discussed SPPC had a maximum capacity of $28 million and minimum capacity of $13 million under the receivables facility. If SPPC does not have sufficient liquidity to meet its power requirements, SPPC may be required to issue or incur additional indebtedness.

In the PUCN order granting the Utilities each $250 million of short-term financing authority, the PUCN removed the NPC dividend restriction that had previously been in place and replaced it with a restriction limiting the total amount of dividends that could be paid by the Utilities. The PUCN limited cash dividends from NPC and SPPC to an aggregate total of $70 million per year from NPC and/or SPPC to SPR until December 31, 2005.

Moreover, in February 2004, NPC amended the dividend restriction contained in its First Mortgage Indenture to (1) change the starting point for the measurement of cumulative net earnings available for the payment of dividends on NPC’s capital stock from March 31, 1953 to July 28, 1999 (the date of NPC’s merger with SPR), and (2) permit NPC to include in its calculation of proceeds available for dividends and other distributions the capital contributions made to NPC by SPR. As amended, NPC does not anticipate that the First Mortgage Indenture dividend restriction will materially limit the amount of dividends that it may pay to SPR in the foreseeable future.

While the Utilities remain subject to a number of restrictions on their ability to pay dividends to SPR, management believes that these restrictions will not prohibit, and that that the Utilities’ cash flows will be sufficient, to dividend $48 million to SPR, which is the amount needed in order for SPR to meet its debt service requirements for 2004.

Regulatory Matters

The Utilities have worked diligently to improve their relationships with the PUCN, including undertaking steps to address prior concerns the PUCN expressed in connection with the March 2002 deferred fuel disallowance. In addition to working closely with the staff of the PUCN to keep them apprised of developments and proactively address any potential concerns, the Utilities continue to work closely with the PUCN in implementing new energy risk management and fuel procurement policies, which are designed to stabilize the Utilities’ risk exposure in the energy market.

The Utilities’ long-term integrated resource plans are filed with the PUCN for approval every three years. Nevada law provides that resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. NPC’s resource plan was filed with the PUCN on July 1, 2003 and was approved in November 2003. SPPC expects to file its plan in July 2004. The Utilities are required to seek PUCN approval for power purchases with terms of three years or more.

Additionally, the Utilities also seek regulatory input and acknowledgement of intermediate term energy supply plans and resource procurement with a one to three year planning horizon. Management believes this is necessary to ensure that the appropriate levels of risks are being mitigated at reasonable costs and are being retained in the portfolio, and decisions to manage risks with the best available information at the point in time when decisions are made are subject to reasonable mechanisms for rate recovery. NPC’s energy supply plan was filed with the PUCN on July 1, 2003 with its 2003-2022 resource plan. The resource plan, including NPC’s recommended natural gas hedging strategy, was approved by the PUCN on November 12, 2003. SPPC’s plan is in the final stages of development and will be filed with the PUCN for informational purposes.

Management believes they have the ability to implement the planned actions and that such actions are designed to mitigate the risks related to the foregoing uncertainties; however, there can be no assurances that management’s actions will fully mitigate these risks and uncertainties. The accompanying financial statements do not include any adjustments that might result from the adverse outcome related to the uncertainties discussed above.

NOTE 3. SEGMENT INFORMATION

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

The net assets and operating results of e ·three and SPC are reported as discontinued operations in the financial statements for 2003, 2002 and 2001. The net assets and operating results of SPPC’s water business, divested in 2001, has been reported as discontinued operations in the financial statements for 2001. Accordingly, the segment information excludes financial information of e ·three, SPC 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 of Notes to Financial Statement, Summary of Significant Accounting Policies. Inter-segment revenues are not material (dollars in thousands).


	NPC			SPPC			Total								Reconciling
December 31, 2003	Electric			Electric			Electric			Gas		All Other			Eliminations		Consolidated
Operating Revenues	$	1,756,146		$	868,280		$	2,624,426		$	161,586	$	1,531		$	—	$	2,787,543
Operating income		183,733			61,323			245,056			7,243		19,165			—		271,464
Operating income taxes (benefit)		(12,734	)		(14,288	)		(27,022	)		584		(30,570	)		—		(57,008	)
Depreciation		109,655			74,432			184,087			7,082		90			—		191,259
Interest expense on long term debt		142,143			69,888			212,031			6,114		75,337			—		293,482
Assets		4,210,759			2,061,255			6,272,014			230,365		490,530			70,849		7,063,758
Capital expenditures		227,066			123,958			351,024			22,937		—			—		373,961


	NPC			SPPC			Total								Reconciling
December 31, 2002	Electric			Electric			Electric			Gas		All Other			Eliminations		Consolidated
Operating Revenues	$	1,901,034		$	931,251		$	2,832,285		$	149,783	$	2,536		$	—	$	2,984,604
Operating income		(104,003	)		49,944			(54,059	)		5,348		21,202			—		(27,509	)
Operating income taxes (benefit)		(133,411	)		(7,236	)		(140,647	)		314		(24,916	)		—		(165,249	)
Depreciation		98,198			70,190			168,388			6,183		(371	)		—		174,200
Interest expense on long term debt		114,527			62,004			176,531			4,470		67,851			—		248,852
Assets		4,166,988			2,104,460			6,271,448			228,067		486,135			124,989		7,110,639
Capital expenditures		294,480			90,343			384,823			14,984		—			—		399,807


	NPC		SPPC		Total							Reconciling
December 31, 2001	Electric		Electric		Electric		Gas		All Other			Eliminations		Consolidated
Operating Revenues	$	3,025,103	$	1,401,778	$	4,426,881	$	145,652	$	2,454		$	—	$	4,574,987
Operating income		144,364		71,219		215,583		7,749		1,309			—		224,641
Operating income taxes (benefit)		17,775		5,534		23,309		2,973		(26,934	)		—		(652	)
Depreciation		93,101		66,393		159,494		5,710		410			—		165,614
Interest expense on long term debt		97,240		53,669		150,909		5,128		51,321			—		207,358
Assets		4,791,261		2,393,284		7,184,545		282,166		580,696			85,320		8,132,727
Capital expenditures		200,852		116,713		317,565		16,041		—			—		333,606

The amounts previously reported differ from the amounts currently reported due to revisions to reflect the discontinued operations presentation of SPC.

The reconciliation of segment assets at December 31, 2003, 2002, and 2001 to the consolidated total includes the following unallocated amounts:


	2003		2002		2001
Cash	$	29,635	$	98,515	$	11,772
Current assets-other		—		—		50,862
Other regulatory assets		31,812		24,555		—
Net Assets-Discontinued Operations		—		—		22,626
Deferred charges-other		9,402		1,919		60

	$	70,849	$	124,989	$	85,320

NOTE 4. 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 gas and electric distribution and transmission operations. NPC and SPPC submit integrated resource plans (IRP) to the PUCN for approval.

Under federal law, the Utilities and TGPC are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

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. Recovery of costs related to the generation divestiture project, which supported Nevada’s now-abandoned utility restructuring policy, were also delayed. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs. NPC renewed its request to recover merger related and divestiture costs in its general rate case which was filed on October 1, 2003.

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 2002 Deferred Energy Case

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

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

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

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

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

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

The BCP filed a Petition that challenged the recovery of all costs with the District Court of Clark County, Nevada, for Judicial Review of the PUCN Order on August 8, 2003, against PUCN, Case No. A471928. On September 8, 2003, the PUCN filed its answer to the BCP Petition. The PUCN response cites a number of affirmative defenses to the allegations contained in the BCP petition and asks that the court dismiss the BCP petition. The BCP filed its opening brief on January 8, 2004. The PUCN and NPC are expected to file responding briefs on March 9, 2004. The court has not ruled on this matter.

Nevada Power Company 2001 Deferred Energy Case

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

On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. NPC and the BCP both sought individual review of the Commission Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal to the Nevada Supreme Court. Supreme Court rules mandate settlement talks before a matter is set for briefing and argument. The Settlement Judge has yet to recommend closure of the settlement process given current caseloads at the Supreme Court. Briefing, oral argument and a decision are not expected to occur until 2005. NPC is not able to predict the outcome of the process or of the Supreme Court’s deliberation on the matter.

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. Recovery of costs related to the generation divestiture project, which supported Nevada’s now-abandoned utility restructuring policy, were delayed. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs. SPPC renewed its request to recover merger and divestiture costs in its general rate case which was filed on December 1, 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 sought to establish a rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase request amounted to 0.01%. The interveners’ testimony was received April 25, 2003, and included proposed disallowances from $34 million to $76 million. Prior to the hearing that was scheduled to begin on May 12, 2003, the parties negotiated a settlement agreement. The agreement included the following provisions:

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

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

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

• Maintain the currently effective Base Tariff Energy Rate.

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

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

• SPPC and the Bureau of Consumer Protection agreed to file a motion to dismiss the civil lawsuits filed in relation to the 2002 SPPC deferred energy case.

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

Sierra Pacific Power Company 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. As part of the settlement agreement reached in connection with SPPC’s 2003 deferred energy case, SPPC agreed to dismiss the lawsuit in May 2003.

Annual Purchased Gas Cost Adjustment 2003 (SPPC)

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

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

As a result of the stipulation, overall, rates for SPPC’s natural gas customers decreased by approximately 3%. The Parties agreed that the new BAA will be amortized over two years with 67% of the balance recovered in the first year, and 33% of the balance recovered in the second year. The BAA rate for the first year will be a credit of $0.06448 per therm. The BAA rate for the second year will be a credit of $0.03176 per therm. A BPGR of $0.66375 per therm was approved, an increase from the previous BPGR of $0.05316 per therm. The new rates were implemented November 1, 2003.

Annual Purchased Gas Cost Adjustment 2002 (SPPC)

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 (BPGR) and an increase in its Balancing Account Adjustment charge (BAA) 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 new rates were implemented January 1, 2003.

NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

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

Sierra Pacific Resources


	December 31,
	2003		2002
Investment in TGTC	$	31,016	$	26,912
Cash Value-Life Insurance		13,065		12,560
Non-utility property of NEICO		3,474		6,555
NVPCT-I & NVPCT-III		5,841		5,841
Southern Service Center Property		12,143		—
Other non-utility Property		7,591		10,201

	$	73,130	$	62,069

Nevada Power


	December 31,
	2003		2002
Cash Value-Life Insurance	$	13,065	$	12,560
Non-utility property of NEICO		3,474		6,555
NVPCT–I & NVPCT-III		5,841		5,841
Southern Service Center Property		12,143		—
Non-utility Property		1,789		1,180

	$	36,312	$	26,136

Sierra Pacific Power


	December 31,
	2003		2002
Non-utility Property	$	916	$	874

NOTE 6. JOINTLY OWNED FACILITIES

At December 31, 2003, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities:


									Construction
	%		Plant		Accumulated		Net Plant		Work in
Generating Facility	Owned		in Service		Depreciation		in Service		Progress
NPC
Navajo Station		11.3	$	205,508	$	105,549	$	99,959	$	3,031
Mohave Facility		14		86,108		45,655		40,453		2,890
Reid Gardner No. 4		32.2		123,832		67,295		56,537		298

Total NPC			$	415,448	$	218,499	$	196,949	$	6,219
SPPC
Valmy Station		50	$	284,709	$	140,784	$	143,925	$	1,885

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.

Because of the coal and water supply issues at Mohave, NPC is preparing for the shutdown of the facility by the end of 2005. NPC’s IRP accepted by the PUCN in November 2003, assumes the Plant will be unavailable after December 31, 2005. In addition, in its General Rate Case filed on October 1, 2003, NPC requested that the PUCN authorize a higher depreciation rate be applied to Mohave in order to recover the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN.

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. 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

Revolving Credit Facilities

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 4 of Notes to Financial Statements, Regulatory Actions) 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 and Refunding Mortgage 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 June 30, 2003, NPC entered into a $60 million revolving Credit Agreement to provide additional liquidity to NPC for its summer 2003 power purchases. This facility was paid off on August 11, 2003, and was terminated on August 18, 2003.

Accounts Receivable Facility

On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million. Actual amounts that may be advanced under the receivables purchase facilities will vary significantly depending upon, among other things, the time of year, the weather conditions and the delinquency notes of NPC’s receivables. Based on 2003 accounts receivables and the variables discussed above, NPC had a maximum capacity of $82 million and minimum capacity of $32 million under the receivables facility. The receivables purchase facility was renewed on October 28, 2003, and expires as of October 26, 2004. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased receivables.

indebtedness, or (2) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively.

Under the terms of the agreements relating to the receivables purchase facility, NPC’s facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of NPC. In addition, the agreements contain a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC’s General and Refunding Mortgage Notes, Series E, described below. SPR has agreed to guaranty NPC’s performance of certain obligations as a seller and servicer under the receivables purchase facility.

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

NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. 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 February 29, 2004, this facility had not been activated.

Sierra Pacific Power Company

Revolving Credit Facilities

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 and Refunding Mortgage Bond which secured the credit facility with a combination of cash on hand and proceeds from its $100 million Term Loan Facility.

On January 30, 2004, SPPC issued its General and Refunding Mortgage Note, Series G, due March 31, 2004, in the maximum principal amount of $22 million under a revolving Credit Agreement. Borrowings under the Series G Note will be used to provide back-up liquidity for SPPC during its 2003-2004 winter peak. Currently, SPPC does not expect to borrow under this facility. The terms of the Series G Note are substantially similar to SPPC’s Term Loan Facility. See Note 8 of Notes to Financial Statements, Long-Term Debt, for further discussion.

Short-Term Financing

On December 22, 2003, SPPC issued and sold its $25 million General and Refunding Mortgage Notes, Series F, due March 31, 2004 in order to provide additional liquidity for SPPC’s fuel and power purchases during its 2003-2004 winter peak. The terms of the Series F Notes are substantially similar to SPPC’s Term Loan Facility.

Accounts Receivable Facility

On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million. Actual amounts that may be advanced under the receivables purchase facilities will vary significantly depending upon, among other things, the time of year, the weather conditions and the delinquency notes of SPPC’s receivables. Based on 2003 accounts receivables and the variables discussed above SPPC had a maximum capacity of $28 million and minimum capacity of $13 million under the receivables facility. The receivables purchase facility was renewed on October 28, 2003, and expires on October 26, 2004. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and natural gas to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for

breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR’s subsidiary will issue variable rate revolving notes backed by the purchased receivables.

The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In additional to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either SPPC or SPR defaults: (1) on the payment of indebtedness, or (2) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively.

Under the terms of the agreements relating to the receivables purchase facility, SPPC’s facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of SPPC. In addition, the agreements contain a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC’s Term Loan Agreement, described below. SPR has agreed to guaranty SPPC’s performance of certain obligations as a seller and servicer under the receivables purchase facility.

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

SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. As of February 29, 2004, this facility had not been activated.

NOTE 8. LONG-TERM DEBT

As of December 31, 2003 NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years is shown below (dollars in thousands):


							SPR Holding
							Co. and Other			SPR
	NPC			SPPC			Subs.			Consolidated
2004	$	135,570		$	83,400		$	19,666	(2)	$	238,636
2005		6,091			100,400			300,000			406,491
2006		6,509			52,400			—			58,909
2007		5,949			2,400			240,218			248,567
2008		7,066			322,400			—			329,466

		161,185			561,000			559,884			1,282,069
Thereafter		1,886,023			437,850			300,000	(1)		2,623,873

		2,047,208			998,850			859,884			3,905,942
Unamortized (Discount Amount)		(11,929	)		(2,650	)		(7,171	)		(21,750	)

Total	$	2,035,279		$	996,200		$	852,713		$	3,884,192

(1)		SPR’s “Thereafter” amount of $300 million represents the total amount of the 7.25% Convertible Notes due at maturity. This differs from the carrying value of $234,118 million included in the balance sheet amount of Long-term debt, which is being accreted to face value using the effective interest method.

(2)		Amount represents debt owed by SPC that has been reclassified to Liabilities of Discontinued Operations. See Sierra Pacific Communications later in this note.

The preceding table includes obligations related to capital lease obligations discussed under lease commitments within this note.

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 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 September 20, 2001 and October 15, 2001, NPC issued an aggregate total of $210 million of 6% unsecured notes due September 15, 2003. NPC satisfied its obligations with respect to these note with a portion of the proceeds from the sale of its 9% General and Refunding Mortgage Notes, Series G, due 2013, discussed below.

On October 18, 2001, NPC issued $140 million of its General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. NPC satisfied its obligations with respect to these notes with a portion of the proceeds from the sale of its 9% General and Refunding Mortgage Notes, Series G, due 2013, discussed below.

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.

On August 13, 2003, NPC issued and sold $350 million of its 9% General and Refunding Mortgage Notes, Series G, due 2013. The Series G Notes were issued with registration rights. The proceeds of the issuance were used to pay off $210 million of its unsecured 6% Notes due September 15, 2003 and $140 million of its General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. The Series G Notes will mature August 15, 2013.

On December 4, 2003, NPC issued its General and Refunding Mortgage Bond, Series H, in the principal amount of $235 million, to an escrow agent in accordance with the Enron stay order. As long as the bonds remain in escrow, they will not be recorded in Long-Term Debt on NPC’s balance sheet. See Note 15 of Notes to Financial Statements, Commitments and Contingencies of the Consolidated Financial Statements, for more information regarding the Enron litigation. The Series H Bond will be held in escrow until such time as the stay order is lifted, entry of an order affirming the judgment and a denial of stay of such order, or a settlement agreement is entered into between NPC and Enron. On February 10, 2004, in accordance with the terms of the Enron stay order, NPC deposited approximately $24 million into the escrow account which amount was deducted from the outstanding principal amount of the Series H Bond. The terms of the Series H Bond are substantially similar to NPC’s Series G Notes.

The Series E and Series G Notes limit the amount of payments in respect of common stock dividends that NPC may pay to SPR. This limitation is discussed in Note 10 of Notes to Financial Statements, Dividend Restrictions.

The terms of the Series E Notes, Series G Notes and Series H Bond also restrict NPC from incurring any additional indebtedness unless:

(1) 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

(2) the debt incurred is specifically permitted under the terms of the applicable Notes or Bond, 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, or

(3) in the case of the Series G Notes and the Series H Bond, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 IRP.

If NPC’s Series E Notes, Series G Notes or Series H Bond are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes or the Bond remains investment grade.

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

Preferred Trust Securities

NVP Capital I Trust

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. As discussed in Note 1, Summary of Significant Accounting Policies, Recent Pronouncements, FIN 46® required the Trust be deconsolidated, as such, the Trust Preferred Securities are no longer consolidated with NPC and the Junior Subordinated Debt is now presented as Long-Term Debt.

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 QUIDS are sufficient to provide the trust with funds to pay the required cash distribution on the QUIPS and the common securities of the trust. The Series A QUIPS are subject to mandatory redemption, in whole or in part, upon repayment of the Series A QUIDS at maturity or their earlier redemption in an amount equal to the amount of related Series A QUIDS maturing or being redeemed. The QUIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption.

NVP Capital III Trust

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. As discussed in Note 1, Summary of Significant Accounting Policies, Recent Pronouncements, FIN 46® required the Trust be deconsolidated, as such, the Trust Preferred Securities are no longer consolidated with NPC and the Junior Subordinated Debt is now presented as Long-Term Debt.

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.

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

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 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. 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 Series B General and Refunding Mortgage Bond.

SPPC’s Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. This limitation is discussed in Note 10 of Notes to Financial Statements, Dividend Restrictions.

SPPC’s Term Loan Agreement 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,

(1) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003,

(2) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and

(3) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for 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 for below of not less than

(1) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002, March 31, 2003, and June 30, 2003,

(2) 1.85 to 1.0 for the fiscal quarter ended September 30, 2003,

(3) 2.00 to 1.0 for the fiscal quarter ended December 30, 2003,

(4) 2.25 to 1.0 for the fiscal quarter ended March 31, 2004,

(5) 2.40 to 1.0 for the fiscal quarter ended June 30, 2004,

(6) 2.70 to 1.0 for the fiscal quarter ended September 30, 2004, and

(7) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter.

As of December 31, 2003, 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. Currently, SPPC is exploring the possibility of taking advantage of favorable conditions in the capital markets by entering into new financings to refinance existing debt, including the Term Loan Facility, on more favorable terms. In the event that SPPC does refinance its Term Loan Facility, after the maturity of SPPC’s Series F General and Refunding Mortgage Notes due March 31, 2004 and SPPC’s Series G General and Refunding Mortgage Note due March 31, 2004, the covenants in the Term Loan Facility will continue to remain in effect under the terms of SPPC’s Series E General and Refunding Mortgage Bond (discussed below).

On December 4, 2003, SPPC issued its General and Refunding Mortgage Bond, Series E, in the principal amount of $103 million, to an escrow agent in accordance with the Enron stay order. As long as the bonds remain in escrow, they will not be recorded in Long-Term Debt on SPPC’s balance sheet. See Note 15 of Notes to Financial Statements, Commitments and Contingencies for more information regarding the Enron litigation. The Series E Bond will be held in escrow until such time as the stay order is lifted, entry of an order affirming the judgment and a denial of stay of such order, or a settlement agreement is entered into between SPPC and Enron. On February 10, 2004, in accordance with the terms of the Enron stay order, SPPC deposited approximately $11 million into the escrow account which amount was deducted from the outstanding principal amount of the Series E Bond. The terms of the Series E Bond are substantially similar to SPPC’s Term Loan Facility.

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 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.

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 of 1933. Currently, 4,804,350 PIES and approximately $240 million of senior unsecured notes remain outstanding.

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. See further discussion regarding the forward stock purchase contract in Note 16 of Notes to Financial Statements, Common Stock And Other Paid-In-Capital.

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, 2003, the purchase contract adjustment payment liability was $5.0 million.

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

In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003, in exchange for 1,295,211 million shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933.

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Interest is payable semi-annually. At December 31, 2003 the carrying value of the Convertible Notes is approximately $234 million with an effective interest rate of 12.5%. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes were used to repurchase approximately $58.5 million of SPR’s Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million were used to repay SPR’s Floating Rate

Notes due April 20, 2003, and the remaining proceeds were available for general corporate purposes. The Convertible Notes were issued with registration rights.

On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. Before SPR received shareholder approval, holders of the Convertible Notes were entitled to receive both shares of common stock and cash upon conversion on their notes. As a result of receiving shareholder approval, through the close of business on February 14, 2010, for each $1,000 principal amount of the Convertible Notes surrendered, SPR has the option to issue:

(1) 76.7073 shares of Common Stock plus an amount of cash equal to the then market value of 142.4564 shares of SPR Common Stock, subject to adjustment upon the occurrence of certain dilution events; or

(2) 219.1637 shares of SPR Common Stock, subject to adjustment upon the occurrence of certain dilution events.

If the noteholders present the Convertible Notes for conversion and SPR elects to convert the notes into stock and cash, the total amount of the cash payable on conversion would be approximately $340 million, at an assumed five-day average closing price of $7.97 per share (based upon the last reported sale price of SPR’s common stock on February 27, 2004. The amount of cash payable on conversion of the Convertible Notes will increase as the average closing price of SPR’s common stock increases.

As a result of the shareholder approval discussed above, the conversion of the Convertible Notes may be fully satisfied by the issuance of stock at SPR’s election. As such, the portion that previously would have been required to have been settled in cash has been reclassified as a long-term liability. See Note 11 of Notes to Financial Statements, Derivative and Hedging Activities for the effects of the Conversion option.

The Convertible Notes provide for the payment of dividends to the holders in an amount equal to any per share dividends on SPR common stock that would have been payable to the holders if the holders of the notes had converted their notes into shares of common stock at the applicable conversion rate on the record date for such dividend. See Note 18 of Notes to Financial Statements, Earnings Per Share for the effect on SPR’s earnings per share calculations.

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

SPC was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. Since that time SPC has developed two distinct businesses. The first is the development of a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (the System) and the second is the Metro Area Network (MAN) business in Las Vegas and Reno, Nevada.

In September 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America (TAI), 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. In June 2003, TAI and all its subsidiaries (including STA/TAI) filed for Chapter 11 bankruptcy protection. In July 2003, SPC filed a motion with the bankruptcy court for automatic stay relief, specifically to obtain approval of the offset of construction costs and other system-related costs against the promissory note. SPC’s position is that no payments are currently due on the note, and that SPC does not have an obligation to make payments on the note during pendency of the motion. STA and the creditors dispute this position. Currently, the parties are engaging in settlement discussions. A final hearing date has not been set. The remaining balance is approximately $19.7 million as of December 31, 2003. The amount has been reclassified to Liabilities of Discontinued Operations. See Note 19, Discontinued Operations and Disposal and Impairment of Long-Lived Assets for further discussion on the disposal of SPC.

Lease Commitments

In 1984, NPC entered into a 30-year capital lease with five-year renewal options beginning in year 2015. 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 capital leases, combined, as of December 31, 2003, were as follows (dollars in thousands):


2004	$	5,557
2005		6,076
2006		6,494
2007		5,932
2008		7,053
Thereafter		37,475

NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2003, carrying amount of 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 NPC’s consolidated long-term debt at December 31, 2003, is estimated to be $1.9 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.3 billion at December 31, 2002.

The total fair value of SPPC’s consolidated long-term debt at December 31, 2003, is estimated to be $936.5 million (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $851.5 million as of December 31, 2002.

The total fair value of SPR’s consolidated long-term debt at December 31, 2003, is estimated to be $3.88 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 $2.66 billion as of December 31, 2002.

NOTE 10. 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.

Dividend Restrictions Applicable to Nevada Power Company

• NPC’s Indenture of Mortgage, dated as of October 1, 1953, between NPC and Deutsche Bank Trust Company Americas, as trustee (the “First Mortgage Indenture”), limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock. In February 2004, NPC amended this restriction in its First Mortgage Indenture to:

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

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

As amended, NPC’s First Mortgage Indenture dividend restriction is not expected to materially limit the amount of dividends that it may pay to SPR in the foreseeable future.

• NPC’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued on August 13, 2003, and NPC’s General and Refunding Mortgage Bond, Series H, which was issued December 4, 2003, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s Premium Income Equity Securities (PIES)) provided that:

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

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

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

The terms of both series of Notes and the Bond also permit NPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed: (1) under the Series E Notes, $15 million from the date of the issuance of the Series E Notes, and (2) under the Series G Notes and the Series H Bond, $25 million from the date of the issuance of the Series G Notes and the Series H Bond, respectively.

In addition, NPC may make payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment:

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

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

• the total amount of such dividends is less than:

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

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

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

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

If NPC’s Series E Notes, Series G Notes or Series H Bond are upgraded to investment grade by both Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s Rating Group, Inc. (S&P), these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes or the Bond remains investment grade.

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

• 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.

Dividend Restrictions Applicable to Sierra Pacific Power Company

• SPPC’s Term Loan Agreement dated October 30, 2002, as amended, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $90 million, $80 million, and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004, and 2005, respectively. SPPC’s General and Refunding Mortgage Bond, Series E, General and Refunding Mortgage Notes, Series F and General and Refunding Mortgage Note, Series G, contain the same dividend restriction as the Term Loan Agreement.

The Term Loan Agreement, the Series E Bond, the Series F Notes and the Series G Note, also permit SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the applicable financing agreement or security, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the such financing agreement or securities, do not exceed the sum of:

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

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

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

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

Dividend Restrictions Applicable to Both Utilities

• On December 17, 2003, the PUCN issued an order in connection with its authorization of the issuance of short-term debt securities by NPC and SPPC. The PUCN order, for Dockets 03-10022 and 03-10023, permits NPC and SPPC to dividend an aggregate of $70 million per year to SPR through December 31, 2005. The PUCN order also provides that the dividend limitation may be reviewed in a subsequent application to grant short-term debt authority and that, in the event that exigent circumstances are experienced in the interim, either NPC or SPPC may petition the PUCN to review the dollar limitation.

• The Utilities are subject to the provision of the Federal Power Act, as applied to their particular circumstance that states that dividends cannot be paid out of funds that are properly included in their capital account. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

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

Assuming that NPC and SPPC meet the requirements to pay dividends under the Federal Power Act and that any dividends paid to SPR are for SPR’s debt service obligations and current operating expenses, the most restrictive of the dividend restrictions applicable to the Utilities individually can be found for NPC, in NPC’s Series E Notes and, for SPPC, in SPPC’s Term Loan Agreement and in the financing agreements that contain substantially similar terms as the Term Loan Agreement. The dividend restriction in the PUCN order is the most restrictive provision applicable to both Utilities and may be more restrictive than the individual dividend restrictions if dividends are paid from both Utilities because the $70 million PUCN dividend restriction is less than the aggregate amount of the Utilities’ most restrictive individual dividend restrictions.

NOTE 11. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)

SPR, SPPC, and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change unless the derivative qualifies as an effective hedge.

SPR’s and the Utilities’ current objective in using derivatives is primarily to reduce exposure to energy price risk. Energy price risks result from activities that include the generation and procurement of power and the procurement 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.

The following table shows the amounts recorded on the Consolidated Balance Sheets of SPR, NPC and SPPC at December 31, 2003 and 2002, due to the fair value of the derivatives. Due to deferred energy accounting under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized (dollars in millions):


	2003						2002
	SPR		NPC		SPPC		SPR		NPC		SPPC
Risk Management Assets	$	22.1	$	11.7	$	10.4	$	29.9	$	28.5	$	1.4
Risk management liabilities	$	16.5	$	5.3	$	11.2	$	73.9	$	29.9	$	44.0
Risk management regulatory assets	$	14.3	$	3.1	$	11.2	$	45.0	$	1.5	$	43.5

Also included in risk management assets were $19.6 million, $9.4 million, and $10.2 million in payments for gas options by SPR, NPC, and SPPC, respectively, at December 31, 2003. In addition, for the year ended December 31, 2003 and 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 are reclassified into earnings when the related transactions are settled or terminate. Accordingly, $1.5 million relating to SPR’s terminated interest rate swap was reclassified into earnings during the twelve months ended December 31, 2003. The corresponding debt matured in April 2003.

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

In connection with SPR’s issuance of its Convertible Notes on February 14, 2003 (see Note 8 of Notes to Financial Statements, Long-Term Debt), the conversion option, which is treated as a cash-settled written call option, was separated from the debt and accounted for separately as a derivative instrument in accordance with FASB’s EITF Issue 90-19, “Convertible Bonds with Issuer Option to Settle for Cash upon Conversion.” Upon issuance, the fair value of the option was recorded as a current liability in Other Current Liabilities and until August 11, 2003, the change in the fair value was recognized in earnings in the period of the change.

On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash portion of the conversion price. Before SPR received shareholder approval, holders of the Convertible Notes were entitled to receive both shares of common stock and cash upon conversion on their notes. Issue No. 00-19 of the EITF of the FASB, “Accounting for Derivative Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock” provides for the recording of the fair value of the derivative in equity, if all of the applicable provisions of EITF Issue No. 00-19 are met. As of August 11, 2003, management believes that all such applicable provisions have been met. Accordingly, the fair value of the derivative, $118 million on the date of the shareholder vote, was reclassified to equity at that date. The fair value of this option was determined using the closing stock price, which was $4.68 as of August 11, 2003, the strike price for conversion ($4.5628), a measurement for the volatility of the stock price and the time value of money. The August 11, 2003 valuation resulted in an unrealized gain of $61.5 million in the third quarter of 2003. The valuations at March 31, 2003, and June 30, 2003, resulted in an unrealized gain of $15.9 million in the first quarter and an unrealized loss of $123.5 million in the second quarter. The net impact of changes in market value was an unrealized loss of $46.1 million for the twelve months ended December 31, 2003. EITF Issue No. 00-19 also indicates that subsequent changes in fair value should not be recognized as long as the derivative remains classified in equity. Accordingly, no unrealized gains or losses were recorded after August 11, 2003.

NOTE 12. INCOME TAXES (Benefits)

Sierra Pacific Resources

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


	2003			2002			2001
As Reflected in Statement of Income:
Federal income taxes (benefits) Current tax expense	$	2,700		$	(89,676	)	$	(421,149	)
Amortization of excess deferred taxes		(2,196	)		(2,196	)		(2,196	)
Amortization of investment tax credits		(3,163	)		(3,454	)		(3,520	)
Deferred income expense		(54,349	)		(69,923	)		429,377

Total federal income taxes		(57,008	)		(165,249	)		2,512
State income taxes (benefits)		—			—			(3,164	)

Federal and state income tax (benefits) on operating income		(57,008	)		(165,249	)		(652	)


	2003			2002			2001
Other income—net
Current tax expense (benefit)		12,781			3,778			14,853
Deferred income expense (benefit)		20			280			17

Total taxes included in other income—net		12,801			4,058			14,870

Total	$	(44,207	)	$	(161,191	)	$	14,218

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


	2003			2002			2001
Income/(Loss) from continuing operations	$	(104,160	)	$	(294,979	)	$	35,818
Total income tax expense (benefit)		(44,207	)		(161,191	)		14,218

		(148,367	)		(456,170	)		50,036
Statutory tax rate		35	%		35	%		35	%

Expected income tax expense (benefit)		(51,928	)		(159,660	)		17,513
Depreciation related to difference in costs basis for tax purposes		4,225			3,081			2,944
Allowance for funds used during construction—equity		(2,018	)		112			85
Convertible bond mark to market and interest accretion		18,291			—			—
ITC amortization		(3,163	)		(3,454	)		(3,454	)
State taxes (net of federal benefit)		—			—			(2,057	)
Pension benefit plan		(1,113	)		1,400			697
Other—net		(5,370	)		(2,670	)		(1.510	)

	$	(41,076	)	$	(161,191	)	$	14,218

Effective tax rate before effect of federal income tax settlement		27.7	%		35.3	%		28.4	%

Effects of federal income tax settlement		(3,131	)		—			—

	$	(44,207	)	$	(161,191	)	$	14,218

Effective tax rate		29.8	%		35.3	%		28.4	%

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 SPR’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 purchased power. At December 31, 2003, SPR reached settlements with the IRS for certain matters including the 1997- 2001 tax years. As a result of the settlements, SPR recognized tax benefits which increased net income by approximately $3.1 million.

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


	2003		2002
Deferred Federal Income Tax Assets:
Net operating loss carryforward	$	276,554	$	281,866
Avoided interest capitalized		37,568		32,319
Employee benefit plans		12,415		13,421
Reserve for bad debts		15,721		15,121
Contributions in aid of construction and customer advances		121,171		109,877
Gross-ups received on contribution in aid of construction and customer advances		19,264		16,665
Excess deferred income taxes		17,469		16,460
Unamortized investment tax credit		24,409		26,258
Additional minimum pension liability		16,207		24,905
Deferred amortization of land gain		13,759		—
Provision for Contract Termination		137,181		109,408
Other		6,775		7,446

		698,493		653,746


	2003		2002
Deferred Federal Income Tax Liabilities:
Allowance for funds used during construction—debt	$	18,678	$	16,281
Bond redemptions		10,712		11,132
Excess of tax depreciation over book depreciation		594,171		555,811
Severance programs		5,890		5,019
Tax benefits flowed through to customers		155,547		163,889
Deferred energy		278,229		339,640
Divestiture Costs		11,758		—
Ad valorem taxes		3,372		3,336
Merger amortizations		5,836		4,378
Other		19,235		14,642

		1,103,428		1,114,128

Net Deferred Federal Income Tax Liability	$	404,935	$	460,382

SPR’s balance sheets contain a net regulatory asset of $113.6 million at December 31, 2003 and $121.1 million at December 31, 2002. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $155.5 million at December 31, 2003 and $163.9 million at December 31, 2002, 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 $17.5 million at December 31, 2003 and $16.5 million at December 31, 2002, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $24.4 million at December 31, 2003 and $26.3 million at December 31, 2002 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 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 period in which these losses could be carried back to prior taxable years from two years to five years. As of December 31, 2003, unutilized net operating losses (NOLs) were $276.6 million. The NOLs 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 NOLs incurred is 20 years, and as such the losses incurred in the years ended December 31, 2001, 2002, and 2003 will expire in 2021, 2022, and 2023 respectively.

Based on estimated future taxable income of SPR, the NOL is expected to be fully utilized by 2008. Accordingly, no valuation allowance has been recorded as of December 31, 2003 because it is more likely than not that the NOLs will be fully utilized.

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.

Nevada Power Company

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


	2003			2002			2001
As Reflected in Statement of Income:
Federal income taxes (benefits)
Current tax expense	$	20,512		$	(45,851	)	$	(324,725	)
Amortization of excess deferred taxes		(499	)		(499	)		(499	)
Amortization of investment tax credits		(1,630	)		(1,630	)		(1,630	)
Deferred income expense		(31,117	)		(85,431	)		345,569

Total federal income taxes		(12,734	)		(133,411	)		18,715
State income taxes (benefits)		—			—			(940	)

Federal and state income tax (benefits) on operating income		(12,734	)		(133,411	)		17,775
Other income—net
Current tax expense (benefit)		12,100			1,347			14,945
Deferred income expense (benefit)		20			280			17

Total taxes included in other income—net		12,120			1,627			14,962

Total	$	(614	)	$	(131,784	)	$	32,737

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


	2003			2002			2001
Income/(Loss) from continuing operations	$	19,277		$	(235,070	)	$	63,405
Total income tax expense (benefits)		(614	)		(131,784	)		32,737

		18,663			(366,854	)		96,142
Statutory tax rate		35	%		35	%		35	%

Expected income tax expense		6,532			(128,399	)		33,650
Depreciation related to difference in costs basis for tax purposes		1,431			1,431			1,431
Allowance for funds used during construction—equity		(996	)		153			383
State taxes (net of federal benefit)		—			—			(611	)
ITC amortization		(1,630	)		(1,630	)		(1,630	)
Other—net		(525	)		(3,339	)		(486	)

	$	4,812		$	(131,784	)	$	32,737

Effective tax rate before effects of federal income tax settlement		25.8	%		35.9	%		34.1	%

Effects of federal income tax settlement		(5,426	)		—			—

	$	(614	)	$	(131,784	)	$	32,737

Effective tax rate		(3.3	)%		35.9	%		34.1	%

The IRS began an audit of SPR’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 purchased power. At December 31, 2003, SPR reached settlements with the IRS for certain matters including the 1997- 2001 tax years. As a result of the settlements, NPC recognized tax benefits which increased net income by approximately $5.4 million.

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


	2003			2002
Deferred Federal Income Tax Assets:
Net Operating Loss Carryforwards	$	214,617		$	250,054
Avoided interest capitalized		19,702			15,202
Employee benefit plans		5,936			9,025
Reserve for bad debts		14,104			11,501
Contributions in aid of construction and customer advances		81,621			72,018
Gross-ups received on contributions in aid of construction and customer advances		13,348			11,054
Excess deferred income taxes		4,860			5,360
Unamortized investment tax credit		10,916			11,940
Additional minimum pension liability		1,512			4,838
Deferred amortization of land gain		13,759			—
Provision for Contract termination		99,391			79,036
Other—net		(377	)		3,674

		479,389			473,702

Deferred Federal Income Tax Liabilities:
Allowance for funds used during construction—debt	$	10,691		$	9,238
Bond redemptions		4,884			5,170
Excess of tax depreciation over book depreciation		347,280			304,002
Severance programs		2,606			2,606
Tax benefits flowed through to customers		102,282			106,070
Deferred energy		216,494			257,614
Divestiture costs		7,114			—
Ad valorem taxes		3,372			3,336
Merger amortizations		2,892			2,000
Other—net		4,152			3,969

		701,767			694,005

Net Deferred Federal Income Tax Liability	$	222,378		$	220,303

NPC’s balance sheet contains a net regulatory asset of $86.5 million at December 31, 2003 and $88.8 million at December 31, 2002. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $102.3 million at December 31, 2003 and $106.1 million at December 31, 2002, due to flow-through of the tax benefits of temporary differences. Offset against this amount are future revenues to be refunded to customers (a regulatory liability), consisting of $4.9 million at December 31, 2003 and $5.4 million at December 31, 2002 due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $10.9 million at December 31, 2003 and $11.9 million at December 31, 2002 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.

Based on estimated future taxable income of NPC, the NOL is expected to be fully utilized by 2008. Accordingly, no valuation allowance has been recorded as of December 31, 2003 because it is more likely than not that the NOLs will be fully utilized.

Sierra Pacific Power Company

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


	2003			2002			2001
As Reflected in Statement of Income:
Federal income taxes (benefits)
Current tax expense	$	9,250		$	(18,909	)	$	(69,490	)
Amortization of excess deferred taxes		(1,697	)		(1,697	)		(1,697	)
Amortization of investment tax credits		(1,533	)		(1,824	)		(1,890	)
Deferred income expense		(19,724	)		15,508			83,808

Total federal income taxes		(13,704	)		(6,922	)		10,731
State income taxes (benefits)		—			—			(2,224	)

Federal and state income tax (benefits) on operating income		(13,704	)		(6,922	)		8,507
Other income—net
Current tax expense (benefit)		1,467			2,431			(91	)
Deferred income expense (benefit)		—			—			—

Total taxes included in other income—net		1,467			2,431			(91	)

Total	$	(12,237	)	$	(4,491	)	$	8,416

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


	2003			2002			2001
Income/(Loss) from continuing operations	$	(23,275	)	$	(13,968	)	$	22,743
Total income tax expense (benefit)		(12,237	)		(4,491	)		8,416

		(35,512	)		(18,459	)		31,159
Statutory tax rate		35	%		35	%		35	%

Expected income tax expense (benefit)		(12,429	)		(6,461	)		10,906
Depreciation related to difference in costs basis for tax purposes		2,794			1,650			1,513
Allowance for funds used during construction—equity		(1,022	)		(40	)		(298	)
ITC amortization		(1,533	)		(1,824	)		(1,824	)
State taxes (net of federal benefit)		—			—			(1,446	)
Pension benefit plan		(1,113	)		1,400			697
Other—net		(491	)		784			(1,132	)

	$	(13,794	)	$	(4,491	)	$	8,416

Effective tax rate before effects of federal income tax settlement		38.8	%		24.3	%		27.0	%

Effects of federal income tax settlement		1,557			—			—

	$	(12,237	)	$	(4,491	)	$	8,416

Effective tax rate		34.5	%		24.3	%		27.0	%

The IRS began an audit of SPR’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 purchased power. At December 31, 2003, SPR reached settlements with the IRS for certain matters including the 1997- 2001 tax years. As a result of the settlements, SPPC recognized tax expense, which decreased net income by approximately $1.6 million.

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


	2003		2002
Deferred Federal Income Tax Assets:
Net operating loss carryforward	$	—	$	237
Avoided interest capitalized		17,866		17,117
Employee benefit plans		6,479		4,396
Reserve for bad debts		1,617		3,620
Contributions in aid of construction and customer advances		39,550		37,859
Gross-ups received on contributions in aid of construction and customer advances		5,916		5,611
Excess deferred income taxes		12,609		11,100
Unamortized investment tax credit		13,493		14,318
Additional minimum pension liability		267		350
Provision for contract termination		37,790		30,372
Other		2,227		3,514

		137,814		128,494

Deferred Federal Income Tax Liabilities:
Allowance for funds used during construction—debt	$	7,987	$	7,043
Bond redemptions		5,828		5,962
Excess of tax depreciation over book depreciation		246,891		251,809
Severance programs		3,284		2,413
Tax benefits flowed through to customers		53,265		57,818
Deferred energy		61,735		82,026
Divestiture costs		4,644		—
Merger amortizations		2,944		2,378
Other		8,236		3,423

		394,814		412,872

Net Deferred Federal Income Tax Liability	$	257,000	$	284,378

SPPC’s balance sheets contain a net regulatory asset of $27.2 million at December 31, 2003 and $32.4 million at December 31, 2002. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $53.3 million at December 31, 2003 and $57.8 million at December 31, 2002, due to flow-through of the tax benefits of temporary differences. Offset against this amount are future revenues to be refunded to customers (a regulatory liability), consisting of $12.6 million at December 31, 2003 and $11.1 million at December 31, 2002, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $13.5 million at December 31, 2003 and $14.3 million at December 31, 2002 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.

Based on estimated future taxable income of SPPC, the NOL is expected to be fully utilized by 2008. Accordingly, no valuation allowance has been recorded as of December 31, 2003, because it is more likely than not that the NOLs will be fully utilized.

NOTE 13. 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 of five years prior to retirement. SPR also has other postretirement plans which provide medical and life insurance benefits for certain retired employees. The following tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans. This reconciliation is based on a September 30 measurement date (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2003			2002			2003			2002
Change in benefit obligations
Benefit obligation, beginning of year	$	428,976		$	360,678		$	132,169		$	75,442
Service cost		15,206			11,954			2,455			1,287
Interest cost		29,400			27,733			8,883			5,599
Participant contributions		—			—			817			590
Plan amendment & special termination		—			7,938			—			—
Actuarial loss		39,401			50,670			22,079			56,189
Benefits paid		(17,703	)		(29,997	)		(7,133	)		(6,938	)

Benefit obligation, end of year	$	495,280		$	428,976		$	159,270		$	132,169

The accumulated benefit obligations for Pension Benefits at the end of 2003 and 2002 were $397 million and $347 million respectively.

The weighted-average actuarial assumptions used to determine end of year benefit obligations are as follows:


							Other
	Pension						Postretirement
	Benefits						Benefits
	2003			2002			2003			2002
Discount rate		6.00	%		6.75	%		6.00	%		6.75	%
Rate of compensation increase		4.50	%		4.50	%		N/A			N/A

For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate was assumed to remain at 6% for all future years.

The discount rate for pension cost purposes is the rate at which the pension obligations could be effectively settled. This rate is based on high-grade bond yields, after allowing for call and default risk. The yields for 30-year Treasury, Merrill Lynch 10+ High Quality, Moody’s Aa and Moody’s Baa bonds were considered in the selection of the discount rate. SPR elected to use the Moody’s Aa composite bond index, which was 5.86% on the plan measurement date of September 30, 2003, to select the discount rate used in calculating benefit obligations. The maturity dates and amounts of this bond index is estimated to be similar to the timing and expected future benefit payments of the plan.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates (assuming all other assumptions are static) would have the following effect (dollars in thousands):


Effect on the postretirement benefit obligation	2003			2002
Effect of a 1-percentage point increase	$	19,590		$	14,886
Effect of a 1-percentage point decrease	$	(16,086	)	$	(12,324	)

SPR contributions for the Other Postretirement benefits reflect benefit payments made by SPR (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2003			2002			2003			2002
Change in plan assets
Fair value of plan assets, beginning of year	$	238,834		$	275,305		$	48,425		$	61,406
Actual return on plan assets		57,964			(23,090	)		9,709			(6,817	)
SPR contributions		56,417			16,616			222			183
Participant contributions		—			—			817			590
Acquisition and divestiture		—			—			—			—
Benefits paid		(17,703	)		(29,997	)		(7,133	)		(6,937	)

Fair value of plan assets, end of year	$	335,512		$	238,834		$	52,040		$	48,425

The asset allocation for SPR’s pension plans at the end of 2003 and 2002, and the target allocation for 2004, by asset category, follows. The fair value of plan assets for these plans is $335.5 million and $238.8 million, at the end of 2003 and 2002, respectively. The expected long-term rate of return on these plan assets was 8.50% in 2003 and 8.50% in 2002. SPR has established medium and long-term performance objectives for its plan assets to ensure that the returns exceed the actuarial assumption of 8.5%.


				Percentage of
	Target			Plan Assets at
	Allocation			Year End
Asset Category	2004			2003			2002
Equity securities		60	%		60.8	%		56.4	%
Fixed securities		40	%		39.2	%		43.6	%

Total		100	%		100	%		100	%

The asset allocation for the other postretirement benefit plans at the end of 2003 and 2002, and target allocation for 2004, by asset category, follows. The fair value of plan assets for these plans is $52.0 million and $48.4 million at the end of 2003 and 2002, respectively. The expected long-term rate of return on these plan assets was 8.50% in both 2003 and 2002.


				Percentage of
	Target			Plan Assets at
	Allocation			Year End
Asset Category	2004			2003			2002
Equity securities		60	%		60.8	%		73.5	%
Fixed Income securities		40	%		39.2	%		26.5	%

Total		100	%		100	%		100	%

The basic principles directing SPR’s management of the pension and other post-retirement plan assets are ensuring the safety of the principal of the assets and obtaining asset performance to meet the continuing obligations of the plan. SPR strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets. Also, SPR considers the ability of the plan to pay all benefit and expense obligations when due, and to control the costs of administering and managing the plan.

SPR’s investment guidelines prohibit investing the plan assets in real estate, derivatives, and SPR’s own stock. Currently, the plan assets are invested in international and domestic equity securities, and fixed securities which include bonds.

Asset allocation is based on long-term capital market behavior and the liquidity needs of the plan. The financial implications of a wide range of investment alternatives (conservative to aggressive) are evaluated over various time periods. Return, risk and diversification assumptions are established for equities and fixed income. The key decisions focus on balancing the rewards of normal market behavior against the risks of poor market behavior over a three-to-seven year planning period.

Funded Status (dollars in thousands)


							Other Postretirement
	Pension Benefits						Benefits
	2003			2002			2003			2002
Funded Status, end of year	$	(159,768	)	$	(190,142	)	$	(107,230	)	$	(83,744	)
Unrecognized net actuarial losses		146,708			154,222			74,676			61,553
Unrecognized prior service cost		15,036			17,001			660			724
Unrecognized net transition obligation		—			—			8,342			9,311
Contributions made in 4th quarter		40,313			24,495			—			—

Accrued pension and postretirement benefit obligations	$	42,289		$	5,576		$	(23,552	)	$	(12,156	)

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


							Other Postretirement
	Pension Benefits						Benefits
	2003			2002			2003			2002
Prepaid pension asset	$	57,465		$	19,813			N/A			N/A
Accrued benefit liability		(15,176	)		(14,237	)	$	(23,552	)	$	(12,156	)
Intangible asset		15,036			17,001			N/A			N/A
Accumulated other comprehensive income		48,344			72,550			N/A			N/A
Additional minimum liability		(63,380	)		(89,551	)		N/A			N/A

Net amount recognized	$	42,289		$	5,576		$	(23,552	)	$	(12,156	)

At the end of 2003 and 2002, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with a projected benefit obligation in excess of plan assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):


	Projected and
	Accumulated
	Benefit Obligation
	Exceeds the Fair Value of
	Plan’s Assets
End of Year	2003		2002
Projected benefit obligation	$	495,280	$	428,976
Accumulated benefit obligation	$	396,916	$	346,687
Fair value of plan assets	$	335,512	$	238,834

The accumulated postretirement benefit obligation exceeds plan assets for all of SPR’s other postretirement benefit plans.

Expected Cash Flows (dollars in thousands)

Information about the expected cash flows for the pension and other postretirement benefit plans follow:


	Pension Benefits		Other Benefits
Employer Contributions to Funded Plans
2004 (expected)	$	35,500	$	233
Expected Benefit Payments
2004	$	18,293	$	7,288
2005		18,908		7,651
2006		19,925		7,993
2007		21,262		8,364
2008		22,715		8,704
2009–2013		143,710		49,712

The above benefit payments are obligations of the indicated Plan and reflect payments, which do not include employee contributions. The expected benefit payment information that reflects the employer obligation is almost entirely paid from plan assets. A small portion of the pension benefit obligation is paid from the plan sponsor’s assets.

Net periodic pension and other postretirement benefit costs include the following components (dollars in thousands):


	Pension Benefits
	2003			2002			2001
Service cost	$	15,206		$	11,954		$	13,494
Interest cost		29,400			27,733			27,742
Expected return on assets		(21,135	)		(22,768	)		(28,806	)
Amortization of:
Prior service costs		1,966			1,676			1,195
Actuarial losses		10,086			2,252			200

Net periodic benefit cost		35,523			20,847			13,825
Additional charges:
Special termination charges		—			1,646			394

Total net benefit cost	$	35,523		$	22,493		$	14,219


	Other Postretirement Benefits
	2003			2002			2001
Service cost	$	2,455		$	1,287		$	1,922
Interest cost		8,883			5,599			6,358
Expected return on assets		(3,860	)		(5,044	)		(6,774	)
Amortization of:
Prior service costs		63			187			—
Transition obligation		969			969			969
Actuarial losses		2,866			—			—

Net periodic benefit cost		11,376			2,998			2,475
Additional charges:
Special termination charges		—			58			—

Total net benefit cost	$	11,376		$	3,056		$	2,475

Weighted-average assumptions used to determine net periodic cost for indicated years are as follows:


										Other Postretirement
	Pension Benefits									Benefits
	2003			2002			2001			2003			2002			2001
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

For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate was assumed to remain at 6% in all future years.

The expected rate of return on plan assets was determined by considering a realistic projection of what assets can earn, given existing capital market conditions, historical equity and bond premiums over inflation, the effect of “normative” economic conditions that may differ from existing conditions, and projected rates of return on reinvested assets.

The expected long-term rate of return on plan assets is 8.5% in 2004.

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 effect (dollars in thousands):


One percentage point change	Increase		Decrease
Effect on service and interest components of net periodic cost	$	1,028	$	(843	)

There were no significant transactions between the plan and the employer or related parties during 2003, 2002 or 2001.

NOTE 14. STOCK COMPENSATION PLANS

At December 31, 2003, SPR 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 2003, SPR issued nonqualified stock options and restricted stock under the long-term incentive plan.

Non-Qualified Stock Options

Elected officers specifically designated by the Board of Directors are eligible to be awarded nonqualified stock options (NQSO’s) based on the guidelines in the plan. These grants are at 100% of the then current fair market value, and vest over different periods, as stated in the grant. These options have to be exercised within ten years of award and five years after retirement.

NQSO’s granted during 2003 were issued at an option price not less than market value at the date of the grants. The grant of 25,000 options awarded in July 2003, will vest to the participant over six months from the grant date, and the grant 30,000 options awarded in January 2003 were fully vested on the date of grant. The 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, 2003, 2002, and 2001, and changes during the year is presented below:


	2003				2002				2001
			Weighted-				Weighted-				Weighted-
			Average				Average				Average
			Exercise				Exercise				Exercise
Nonqualified Stock Options	Shares		Price		Shares		Price		Shares		Price
Outstanding at beginning of year		1,399,809	$	16.56		1,213,958	$	18.28		799,428	$	19.94
Granted		55,000	$	5.69		502,380	$	14.05		414,530	$	15.08
Exercised		—		—		—		—		—		—
Forfeited		82,940	$	13.25		316,529	$	19.16		—		—
Outstanding at end of year		1,371,869	$	16.33		1,399,809	$	16.56		1,213,958	$	18.28
Options exercisable at year-end		1,369,786	$	16.35		524,301	$	19.07		262,533	$	23.03
Weighted-average grant date fair value of options granted(1):
Average of all grants for:
2003			$	3.61
2002							$	4.56
2001											$	3.83

(1)

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 2003, 2002 and 2001:


	Average			Average			Average
	Dividend			Expected			Risk-Free			Average
Year of Option Grant	Yield			Volatility			Rate of Return			Expected Life
2003		0.00	%		46.97	%		4.64	%	10 years
2002		0.00	%		38.23	%		5.03	%	10 years
2001		4.99	%		32.31	%		5.32	%	10 years

The following table summarizes information about nonqualified stock options outstanding at December 31, 2003:


			Options Outstanding			Options Exercisable
	Average		Number		Remaining			Number
	Exercise		Outstanding at		Contractual	Average		Exercisable at
Year of Grant	Price		12/31/03		Life	Exercise Price		12/31/03
1994	$	14.24		8,003	<1 year	$	14.24		8,003
1995	$	13.02		9,010	1 year	$	13.02		9,010
1996	$	16.23		7,485	2 years	$	16.23		7,485
1997	$	19.97		24,788	3 years	$	19.97		24,788
1998	$	24.93		48,240	4 years	$	24.93		48,240
1999	$	25.11		164,206	5-5.6 years	$	25.11		164,206
2000	$	16.00		400,000	6 years	$	16.00		400,000
2001	$	15.95		266,187	7-7.9 years	$	15.95		266,187
2002	$	7.99		388,950	8-8.9 years	$	7.99		388,950
2003	$	5.65		55,000	9-9.5 years	$	5.65		52,917
Weighted Average Remaining Contractual Life					6.63 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.

In 2003, all of the outstanding performance shares were converted into shares of restricted stock. As a consequence, there are currently no outstanding grants of performance shares.

Restricted Stock Shares

All of the performance shares outstanding at December 31, 2002 were converted into shares of restricted stock.

In 2003, SPR granted an additional 419,376 shares of restricted stock at an average grant price of $6.57 per share. Of the shares granted, 409,376 shares will vest over four years with one-third becoming available in each of the years ended December 31, 2004, 2005, and 2006. The remaining 10,000 shares will vest over three years at one-third per year.

In 2002, SPR granted 4,500 restricted stock shares at an average grant price of $6.55 per share. The grants vest over four years at 25% per year. In 2003, according to the vesting schedule for each grant, 1,125 shares were issued under these grants.

During 2001, SPR granted 13,200 shares of restricted stock at an average grant price of $15.72 per share. The grants vest to the participants over four years at 25% per year. In 2003, in accordance with the conditions of each grant, 675 shares were issued under these grants.

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 100,660, 73,321 and 33,830 shares to employees in 2003, 2002, and 2001, 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 2003, 2002 and 2001, with an option life of six months:


							Average
							Risk-			Weighted
	Average			Average			Free			Average
	Dividend			Expected			Rate of			Fair
Year	Yield			Volatility			Return			Value
2003		0.00	%		52.40	%		0.98	%	$	1.29
2002		0.00	%		38.00	%		3.12	%	$	1.45
2001		5.01	%		32.43	%		2.82	%	$	2.72

NOTE 15. COMMITMENTS AND CONTINGENCIES (SPR, NPC And SPPC)

Purchased Power

At December 31, 2003, 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. In accordance with 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 (QF). As of December 31, 2003, 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, 2003, 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.

Estimated future commitments under non-cancelable agreements (including agreements with QF’s as of December 31, 2003 were as follows (dollars in thousands):

Purchased Power


	NPC		SPPC		Total
2004	$	358,753	$	57,030	$	415,783
2005		301,222		29,385		330,607
2006		240,848		29,969		270,817
2007		210,797		30,767		241,564
2008		192,374		32,259		224,633
Thereafter		2,897,461		5,540		2,903,001

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 2004 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
2004	$	57,414	$	101,025	$	158,439	$	40,025	$	62,519	$	102,544
2005		16,700		18,001		34,701		24,736		57,586		82,322
2006		19,322		18,322		37,644		24,736		52,869		77,605
2007		18,000		—		18,000		24,736		52,822		77,558
2008		—		—		—		24,736		45,684		70,420
Thereafter		—		—		—		245,764		255,662		501,426

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, 2003, were as follows (dollars in thousands):

Operating Leases


	NPC		SPPC		Other Subs		Total
2004	$	1,909	$	8,152	$	177	$	10,238
2005		1,501		7,553		—		9,054
2006		936		7,197		—		8,133
2007		35		5,965		—		6,000
2008		8		5,966		—		5,974
Thereafter		450		22,153		—		22,603

Other

On December 18, 2003, SPPC entered into a 15 year Transportation Service Agreement (the Agreement) with Tuscarora Gas Transmission Company, a related company. The agreement calls for SPPC to take 23,000 dth/day of capacity beginning in the winter of 2005.

Environmental

Nevada Power Company

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generation Station (“Mohave”), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006 for the first and second units, respectively. The estimated cost of new controls is $1.2 billion. As a 14% owner in Mohave, NPC’s cost could be $168 million. However, due to the coal and water issues discussed below it is not the intention of SCE and other owners to proceed with the pollution control equipment.

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

Because of the coal and water supply issues at Mohave, NPC is preparing for the shutdown of the facility by the end of 2005. In July, NPC filed an IRP with the PUCN that assumed the Plant will be unavailable after December 31, 2005. In addition, in its General Rate Case filed on October 1, 2003, NPC requested that the PUCN authorize a higher depreciation rate be applied to Mohave in order to recover the remaining net book value of $40.5 million by end of 2005. Alternatively, NPC requested that the PUCN authorize the transfer of the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN.

In May 1997, the 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 was originally expected to identify remediation requirements of contaminated groundwater resulting from these evaporation ponds by September 2003. Recently, NDEP indicated that remediation requirements will be identified by mid year 2004. New pond construction and lining costs are estimated to cost approximately $25 million, of which, a majority is expected to be spent by the end of 2004.

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

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

NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site has a reclamation estimate supported by a bond of $4.8 million with the Utah Division of Oil and Gas Mining. Currently, management is continuing to evaluate various options including reclamation and sale. At this time the maximum financial impact on the Company is $4.8 million.

Sierra Pacific Power Company

In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRPs formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC recorded a preliminary liability for the Sites of $650,000. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and revise, if necessary, its recorded liability for the Sites.

Lands of Sierra

LOS, a wholly-owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contamination resulting from an underground fuel tank that was removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. On February 3, 2003, the Lahontan Regional Water Quality Control Board re-opened the case against this property. The re-opening occurred due to onsite monitoring, which showed increased levels of contamination. SPR has completed the evaluation of alternative remediation technologies and their effectiveness in reducing contamination at this site. On January 27, 2004, Lahontan Regional Water Quality Board rendered a decision requiring a dual phase water extraction remediation system. The cost to implement this system is not material.

Litigation Contingencies

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

In June 2002, Enron filed a complaint with the Bankruptcy Court against NPC and SPPC (the Utilities) seeking to recover liquidated damages for power supply contracts terminated by Enron in May 2002 and for unpaid power previously delivered to the Utilities (as defined below). The Utilities denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron’s ability to perform) and fraud, unfair trade practices and market manipulation. The Utilities also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for other unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets, wrongful termination of its transactions with the Utilities, and fraudulent inducement to enter into transactions with Enron, among other issues.

On September 26, 2003, the Bankruptcy Court entered a judgment (the Judgment) in favor of Enron for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment requires NPC and SPPC to pay approximately $235 million and $103 million, respectively, to Enron for liquidated damages and pre-judgment interest for power not delivered by Enron under the power supply contracts terminated by Enron in May 2002 and approximately $17.7 million and $6.7 million, respectively, for power previously delivered to the Utilities. The Bankruptcy Court also dismissed the Utilities’ counter-claims against Enron, dismissed the Utilities’ counter-claims against Enron Corp., the parent of Enron, and denied the Utilities’ motion to dismiss or stay the proceedings pending the final outcome of their FERC proceedings against Enron. Based on the pre-judgment rate of 12%, NPC and SPPC recognized additional interest expense of $27.8 million and $12.4 million, respectively, in contract termination liabilities in the third quarter of 2003. Also, NPC and SPPC recorded additional contract termination liabilities for liquidated damages of $6.6 million and $2.1 million, respectively, in the third quarter of 2003. The Bankruptcy Court’s order provides that until paid, the amounts owed by the Utilities will accrue interest post-judgment at a rate of 1.21% per annum.

In response to the Judgment, the Utilities filed a motion with the Bankruptcy Court seeking a stay pending appeal of the Judgment and proposing to issue General and Refunding Mortgage Bonds as collateral to secure payment of the Judgment. On November 6, 2003, the Bankruptcy Court ruled to stay execution of the Judgment conditioned upon NPC and SPPC posting into escrow $235 million and $103 million, respectively, of General and Refunding Mortgage Bonds plus $281,695 in cash by NPC for pre-judgment interest. On December 4, 2003, NPC and SPPC complied with the order of the Bankruptcy Court by issuing their $235 million General and Refunding Mortgage Bond, Series H and $103 million General and Refunding Mortgage Bond, Series E, respectively, into escrow along with the required cash deposits for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which will lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. NPC and SPPC made the payments as ordered on February 10, 2004. The Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall seek a ruling from the PUCN to determine whether the cash payments into escrow trigger the Utilities’ rights to seek recovery of such amounts through their deferred energy rate cases. Furthermore, hearings have been scheduled for March 24, 2004, in front of the Bankruptcy Court to review the Utilities’ abilities to provide additional cash collateral which, if required, would reduce the principal amount of the General and Refunding Mortgage Bonds held in escrow by a like amount.

On October 1, 2003 the Utilities filed a Notice of Appeal from the Judgment with the U.S. District Court for the Southern District of New York. On its appeal the Utilities seek reversal of the Judgment and contend that Enron is not entitled to recover termination charges under the contract on various grounds including breach of contract, breach of solvency representation, fraud, misrepresentation, and manipulation of the energy markets and that the Bankruptcy Court erred in holding that the filed rate doctrine barred various claims which were purported to challenge the reasonableness of the rate. Enron filed a cross appeal on the grounds that the amount of post judgment interest should have been 12% per year instead of 1.21% as ordered by the Bankruptcy Court. The Utilities filed their principal brief on December 30, 2003 and Enron filed its cross-appeal brief and reply brief on January 30, 2004. The Utilities filed a reply brief on March 1, 2004 and Enron is expected to file its final brief thereafter in March 2004. The U.S. District Court could render an opinion any time after the submission of the final briefs. The Utilities are unable to predict the outcome of their appeal of the Judgment.

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

other relief does not yet provide the circumstances of experiencing a cost which can trigger a filing seeking collection from its customer, and because the issues are not ripe, this Petition is not the docket to decide whether recovery of termination payments should be sought through a general rate case or a deferred energy proceeding.”

Through December 31, 2003, interest costs related to the Judgment of $36 million and $16 million for NPC and SPPC, respectively, were charged as interest expense and were not included in their deferred energy balances. If the Utilities are successful in their appeal, amounts previously charged to interest expense would be reversed and recognized in income in the respective period. Similarly amounts for power supply contracts terminated by Enron included in the deferred energy balances would be reversed. If the Utilities are unsuccessful in their appeal, they may seek to recover the interest costs in the deferred account.

Any requirement to pay the Judgment or to provide further cash collateral, described above, for Enron’s claims for termination payments could adversely affect SPR’s, NPC’s and SPPC’s cash flow, financial condition and liquidity, and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.

FERC 206 complaints

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

The Utilities have already paid the full contract price for all power actually delivered by these suppliers, but are contesting those amounts as well as claims made for terminating power suppliers that did not deliver power, including those terminated by Enron.

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

On June 26, 2003, FERC adopted the ALJ’s recommendation and dismissed the Utilities’ Section 206 complaints on a two-to-one vote essentially finding that the strict public interest standard applied to the case and that the Utilities had failed to satisfy the burden of proof required by that standard. In that order, FERC also determined that it would not deem the order final and conclusive as to either of the Utilities’ liability to Enron for purchase power contracts terminated by Enron, which may be challenged in other proceedings, including other proceedings at FERC. On July 28, 2003, the Utilities filed a petition for rehearing at the FERC requesting that the FERC either reconsider or rehear the case. The petition cited several grounds for rehearing, including that the public interest standard did not apply but that even if it did apply the Utilities had satisfied that standard as well as the less onerous just and reasonable standard which the Utilities contend does apply to the case. On November 10, 2003, the FERC issued an Order on Requests for Rehearing and Clarification, which reaffirmed the June 26, 2003 decision (by the same two-to-one margin). The Utilities intend to pursue available appeals of this matter. Under applicable statutes, the Utilities may seek judicial review before the United States Court of Appeals for the District of Columbia Circuit or the Ninth Circuit. That decision has been appealed to the D.C. Circuit Court of Appeals, which has not yet established a briefing schedule. The Utilities are unable to predict the outcome of this appeal at this time.

On October 6, 2003, the Utilities filed a new FERC Section 206 complaint against Enron to prevent Enron from obtaining a final judgment in the Bankruptcy Court case and/or prevent enforcement of any right to collect its termination payments until FERC has had a chance to review the complaint. The new complaint has been designated as Docket No. EL04-1-000. On October 27, 2003, Enron filed an answer to the Utilities’ complaint and the matter is pending. On October 8, 2003, the Nevada Attorney General’s office, through its Bureau of Consumer Protection, intervened on behalf of Nevada citizens, joining NPC and SPPC in opposing Enron’s actions. On October 29, 2003, United States Senators Reid and Ensign of Nevada also filed an intervention joining NPC and SPPC in opposing Enron’s claims to termination payments.

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

The 206 complaint in Docket No. EL04-1-000 asks FERC to issue an order to preserve the status quo by prohibiting Enron from enforcing the termination payment obligations set forth in the judgment until such time as FERC has an opportunity to review the merits of the Utilities’ claims raised in their new FERC Section 206 complaint. The complaint further asks that FERC find that Enron’s actions violated the terms of tariff language rendering Enron unable to collect termination payments; that Enron violated

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

Reliant Antitrust Litigation

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 (original plaintiffs consist of The People of the State of California, City and County of San Francisco, City of Oakland, and County of Santa Clara) 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 spread among all energy suppliers. The trial court has held all answers to cross-claims in abeyance until such time as it decides whether the plaintiffs’ complaint should be dismissed for failing to state a claim for relief and whether the complaint should be dismissed under the filed rate doctrine. The court granted the motion to dismiss and the case is currently on appeal.

Nevada Power Company

Morgan Stanley Proceedings

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

On March 26, 2003, NPC filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada asking the Court to declare that NPC is not liable for any damages as a result of MSCG’s termination of its power supply contracts. On April 17, 2003, MSCG answered the complaint and filed a counterclaim against NPC alleging non-payment of the termination payment in the amount of $25 million. In April 2003 MSCG also filed a complaint against NPC at FERC alleging that NPC should be required to pay MSCG the amount of the claimed termination payment pending resolution of the case. NPC filed a motion to intervene in the FERC action commenced by MSCG and FERC dismissed MSCG’s complaint. NPC is unable to predict the outcome of the District Court complaint.

Reliant Resources and IDACORP Energy, L.P.

On May 3, 2002, and July 3, 2002, respectively, Reliant Resources (Reliant) and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002, and July 10, 2002, Reliant and Idaho asserted claims for $25.6 million and $8.9 million, respectively, under the Western System Power Pool Agreement (WSPP) for liquidated damages under energy contracts that each company terminated before the delivery dates of the power. Such claims are subject to mandatory mediation and, in some cases, arbitration under the contracts. Idaho requested mediation of the contracts. NPC alleges that Idaho and Reliant were participants in market manipulation in the West and therefore are not entitled to termination payments under the contracts. The mediation was not successful and in April 2003 Idaho filed suit in Idaho. NPC moved to dismiss the complaint on jurisdictional grounds and filed its own complaint in State court in Clark County, Nevada in September 2003. The court in Idaho denied NPC’s motion to dismiss without prejudice and ordered some preliminary discovery on the jurisdictional issues. The case in Nevada is currently pending.

In June 2003, Reliant Energy submitted a comprehensive settlement proposal to NPC proposing a settlement of NPC’s termination payment obligation arising out of Reliant’s May 2002 termination of its purchase power contracts with NPC. NPC denies that it owes Reliant any money under these contracts. Mediation of this claim occurred in 2002 and was not successful. Neither party has requested arbitration nor commenced litigation over this dispute, and the parties are continuing discussions.

El Paso Merchant Energy

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.

In June 2003, EPME demanded mediation of its claim for a termination payment arising out of EPME’s September 25, 2002, termination of all executory purchase power contracts between NPC and EPME. EPME claims that under the terms of the contracts, NPC owes EPME approximately $39 million representing the difference between the contract price and the market price for power to be delivered under all the terminated contracts and the amount remaining unpaid under the contracts for power delivered between May 2002 and October 2002. NPC claims that EPME owes NPC an amount up to approximately $162 million for undelivered power representing the difference between the replacement price or market price for power to be delivered under all the executory contracts and the contract price for that power. The mediation was unsuccessful, and on July 25, 2003, NPC commenced an action against EPME and several of its affiliates in the Federal District Court for the District of Nevada for damages resulting from breach of these purchase power contracts. EPME filed a motion to dismiss the complaint on grounds of lack of personal jurisdiction and failure to state a claim for relief. NPC responded to the motion to dismiss on February 27, 2004. EPME’s reply is due March 17, 2004. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Contract Termination Liabilities

At December 31, 2003, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” is $280 million and $105 million, respectively, for terminated power supply contracts and associated interest. Correspondingly, pursuant to the deferred energy accounting provisions of AB 369, included in NPC and SPPC deferred energy balances as of December 31, 2003, is approximately $245 million and $84 million, (which excludes interest costs discussed below) respectively, for recovery in rates in future periods associated with the terminated power supply contracts. If NPC and SPPC are required to pay part or all of the amounts accrued for, the Utilities will pursue recovery of the amounts through future deferred energy filings. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amounts not permitted would be charged as a current operating expense. A significant disallowance of these costs by the PUCN could have a material adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Bonneville Square and Union Plaza

In October 2002, Bonneville Square and Union Plaza filed a complaint seeking class certification in the Eighth 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. Plaintiffs claim that NPC overcharged the class by an indeterminate amount. NPC’s motion to dismiss on jurisdictional grounds was denied and NPC filed a writ before the Nevada Supreme Court, which 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. The matter is currently pending.

Sierra Pacific Resources

Gordon and Anderson

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 Nevada Power Company. 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 in the same court. On March 21, 2003, plaintiffs’ counsel moved to consolidate the Gordon and Anderson cases with another virtually identical lawsuit filed by John Dedolph, also filed in the same court. In July 2003, the cases were consolidated into one action and moved to the Clark County Business Court. On August 22, 2003, the judge dismissed the consolidated cases against SPR.

Touch America and Sierra Touch America LLC

In 2000, SPC, and TA (formerly Montana Power), formed 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 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.

In June 2003, TAI and all its subsidiaries (including STA) filed a petition for Chapter 11 bankruptcy protection. In July 2003, SPC filed a motion with the bankruptcy court for automatic stay relief, specifically to obtain approval of the offset of construction costs and other System-related costs against the promissory note. SPC’s position is that no payments are currently due on the note, and that SPC does not have an obligation to make payments on the note during the pendency of the motion. STA and the creditors dispute this position. A status conference on the motion is scheduled for March 11, 2004, a final hearing date has not been set.

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 or results of operations.

Regulatory Contingencies

The Utilities’ rates are currently subject to the approval of the PUCN and, in the case of SPPC, they are also subject to the approval of CPUC. Such rates are designed to recover the cost of providing generation, transmission, and distribution services. Accordingly, the Utilities qualify for the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” See Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies, for further information.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any pending or potential deregulation legislation. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies, management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge or expensed in current period earnings.

Regulatory Accounting affects Deferred Energy, Goodwill and Merger Costs, Generation Divestiture Costs, and Piñon Pine, all of which are discussed immediately below. To the extent that the Utilities may not be permitted to recover any portion of deferred energy, goodwill and merger costs, generation divestiture costs and long-lived assets (Piñon Pine), the disallowed costs and related carrying charges would be required to be written off in current period earnings, except for Goodwill, which is subject to evaluation for impairment in accordance with the provisions of SFAS No. 142. A significant disallowance of these costs by the PUCN would have a material adverse effect on the future financial position, results of operations, and cash inflows of SPR, NPC, and SPPC.

Deferred Energy

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

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

AB 369 requires the Utilities to file applications to clear their respective deferred energy account balances at least every 12 months and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances. Deferred energy balances subject to PUCN review as of December 31, 2003 are $344 million and $130 million for NPC and SPPC, respectively, including the deferred provision for terminated supply contracts.

Goodwill and Merger Costs

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

Costs deferred as a result of the PUCN order were $325.1 million of goodwill and $62.8 million in other merger costs as of December 31, 2003. The deferred other merger costs consist of $41.5 million of transaction and transition costs and $21.3 million of employee separation costs. Employee separation costs were comprised of $16.8 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains. These amounts are included in NPC’s and SPPC’s current general rate case. We expect a decision in NPC’s case in the later part of March 2004 and late spring 2004 for SPPC.

Generation Divestiture Costs

As a condition to its approval of the merger between SPR and NPC, the Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture Plan stipulation for the sale of the Utilities’ generation assets. In May 2000, an agreement was announced for the sale of NPC’s 14% undivided interest in the Mohave. 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, prohibited the sale of generation assets until July 2003 and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits any further divestiture of generation properties by California utilities until 2006, including SPPC, and could also affect any sale of NPC’s interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison. SPPC’s request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied. In September 2002, the California Legislature approved an exemption to AB 6, which had prevented private utilities from selling any power plants that provide energy to California customers until 2006. The exemption allows SPPC to complete the sale of the hydroelectric units to Truckee Meadows Water Authority (TMWA) subject to review and approval of the sale by the CPUC.

The sales agreements for the six bundles provided that they would terminate eighteen months after their execution and all of the agreements have now terminated in accordance with their respective provisions. As of December 31, 2003, NPC and SPPC had incurred costs, including carrying charges, of approximately $21.9 million and $13.3 million, respectively, in order to prepare for the sale of generation assets. In the fourth quarter of 2001, each Utility requested recovery of its respective costs in its application for a general rate increase filed with the PUCN. In 2002, the PUCN delayed recovery of divestiture costs to future rate case requests and granted a carrying charge on the costs until such time as recovery is allowed. To the extent that the Utilities may not be permitted to recover any portion of these costs in future rates, the disallowed costs and related carrying charges would be required to be written off in current period earnings. These amounts are included in NPC’s and SPPC’s current general rate case. A decision is expected in NPC’s case in the later part of March 2004 and late spring 2004 for SPPC.

Piñon Pine

SPPC owns a combined cycle generation facility, a post-gasification facility, and, through its wholly owned subsidiaries, owns a gasifier that are collectively referred to as the Piñon Pine. Construction of Piñon Pine was completed in June 1998. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $95 million as of December 31, 2003.

To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001, SPPC retained an independent engineering consulting firm to complete a comprehensive study of the Piñon Pine gasification plant. After evaluating the options presented in the draft report, SPPC decided not to pursue modifications intended to make the facility operational and is seeking recovery, net of salvage, through regulated rates in its general rate case, which was filed on December 1, 2003, based, in part, on the PUCN’s approval of Piñon Pine as a demonstration project in an earlier IRP. However, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC’s and SPR’s results of operations.

NOTE 16. COMMON STOCK AND OTHER PAID-IN CAPITAL

Rights Agreement

On September 21, 1999, the Board of Directors of SPR (the Board) declared a dividend distribution of one right (an 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 Rights, the 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 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 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 Right’s then-current exercise price, common stock of such Acquiring Person having a calculated value of twice the Right’s then-current exercise price.

The Rights are not exercisable until the Distribution Date (as defined in the Rights Agreement) and expire on October 31, 2009, unless previously redeemed by SPR. Following a Distribution Date, the Rights will trade separately from the common stock and will be evidenced by separate certificates. Until the 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.

Employee Stock Ownership Plans

As of December 31, 2003, 8,316,624 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 No. 25. In addition, in 1996 SPR 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.

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 2003, 2002 and 2001, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 39,370, 18,540, and 14,573 shares, and $150,000, $160,000, and $210,000.

Public Stock Offering

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.

Stock Exchange Transactions

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.

Convertible Notes Issuance

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. For additional information regarding this transaction see Note 8 of Notes to Financial Statements, Long-Term Debt. On August 11, 2003, SPR obtained shareholder approval to issue additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. If the noteholders were to present the Convertible Notes for conversion and SPR were to fully convert the notes into stock, the number of additional shares required would be 65,749,110.

The Convertible Notes provide for the payment of dividends to the holders in an amount equal to any per share dividends on SPR common stock that would have been payable to the holders if the holders of the notes had converted their notes into shares of common stock at the applicable conversion rate on the record date for such dividend. See Note 18, Earnings Per Share for a discussion on the effect on the convertible notes and the calculation of basic and diluted EPS.

NOTE 17. PREFERRED STOCK

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 23, 2004, a dividend of $975,000 ($0.4875 per share) was declared on SPPC’s preferred stock. The dividend was paid on March 1, 2004, to holders of record as of February 14, 2004.

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


	Amount				Shares Outstanding
	2003		2002		2003		2002
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

NOTE 18. EARNINGS PER SHARE (EPS)

The difference, if any, between Basic EPS and Diluted EPS is due to potentially diluted common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, the non-employee director stock plan and dividend participation rights associated with the convertible debt. However, due to net losses for the twelve-month periods ended December 31, 2003 and 2002 these items are anti-dilutive. Accordingly, Diluted EPS for these periods are computed using the weighted average shares outstanding before dilution. Potentially diluted common shares were determined using the treasury stock method or the “two class” method as discussed below.

EITF 03-06 requires the use of the two-class method, as described in SFAS 128 “Earnings Per Share,” for including participating convertible securities in the computation of basic EPS. Furthermore, the EITF nullified EITF Topic D-95 “Effect of Participating Convertible Securities on the Computation of Basic Earnings Per Share,” which allowed for the use of either the “if-converted” method or the “two-class” method in basic EPS calculations. Previously, SPR applied the “if-converted” method to the dividend participation rights associated with the convertible debt. As of March 31, 2004, SPR has changed its accounting policy and will now use the “two-class” method in basic EPS calculations. The effect of the dividend participation rights, under the “two-class” method, are anti-dilutive for the year ending December 31, 2003, and as such they have not been included in the basic earnings per share calculation.

The following table outlines the calculation for (EPS).


	2003			2002			2001
Basic EPS
Numerator ($000)
Income / (Loss) from continuing operations	$	(104,160	)	$	(294,979	)	$	35,818
Gain / (Loss) on discontinued operations	$	(32,469	)	$	(7,076	)	$	24,615
Cumulative effect of change in accounting principle	$	—		$	(1,566	)	$	—
Income / (Loss) applicable to common stock	$	(140,529	)	$	(307,521	)	$	56,733
Denominator
Weighted average number of shares outstanding		115,774,810			102,126,079			87,542,441

Per-Share amount
Income / (Loss) from continuing operations	$	(0.90	)	$	(2.89	)	$	0.41
Gain / (Loss) on discontinued operations	$	(0.28	)	$	(0.07	)	$	0.28
Cumulative effect of change in accounting principle	$	—		$	(0.02	)	$	—
Income / (Loss) applicable to common stock	$	(1.21	)	$	(3.01	)	$	0.65
Diluted EPS
Numerator ($000)
Income / (Loss) from continuing operations	$	(104,160	)	$	(294,979	)	$	35,818
Gain / (Loss) on discontinued operations	$	(32,469	)	$	(7,076	)	$	24,615
Cumulative effect of change in accounting principle	$	—		$	(1,566	)	$	—
Income / (Loss) applicable to common stock	$	(140,529	)	$	(307,521	)	$	56,733

Denominator(1)
Weighted average number of shares outstanding before dilution		115,774,810			102,126,079			87,542,441
Stock options		—			—			14,021
Executive long term incentive plan—performance shares(2)		—			—			43,693
Executive long term incentive plan—restricted shares(3)		—
Non-Employee Director stock plan		—			—			9,355
Employee stock purchase plan		—			—			2,862
Dividend participation rights		—			—			—

Weighted average number of shares outstanding after dilution(4)		115,774,810			102,126,079			87,612,372

Per-Share Amount
Income / (Loss) from continuing operations	$	(0.90	)	$	(2.89	)	$	0.41
Gain / (Loss) on discontinued operations	$	(0.28	)	$	(0.07	)	$	0.28
Cumulative effect of change in accounting principle	$	—		$	(0.02	)	$	—
Income / (Loss) applicable to common stock	$	(1.21	)	$	(3.01	)	$	0.65

(1)		The denominator does not include anti-dilutive shares for the Stock Option Plan and Corporate PIES due to conversion prices being higher than market prices at December 31, 2003. The amounts that would be included in the calculation if the conversion prices were met would be 1.4 million shares for the Stock Option Plan and 17.3 million shares for Corporate PIES.

(2)		Plan terminated in 2002.

(3)		New plan for 2003.

(4)		For the twelve months ended December 31, 2003 and 2002 the weighted average number of shares after dilution excludes shares of 65,836,431 and 32,096, respectively for stock options, executive long-term incentive plan - - performance shares, executive long term incentive plan — restricted shares, non-employee stock plan, Employee stock purchase plan and dividend participation rights as they would be anti-dilutive.

NOTE 19. DISCONTINUED OPERATIONS AND DISPOSAL AND IMPAIRMENT OF LONG-LIVED ASSETS

Effective January 1, 2002, SPR, NPC and SPPC 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. Further, SFAS No. 144 requires that assets to be held and used be tested for recoverability whenever events or circumstances indicate that its carrying amount may not be recoverable.

Discontinued Operations

e ·three Business Sale

SPR’s subsidiary, e ·three, was organized in October 1996 to provide energy and other business solutions in commercial and industrial markets.

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. Accordingly, on June 30, 2003, e ·three was reported as a discontinued operation. 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 was 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 operation of e ·three was included in the “Other” business segment.

The operation of e ·three discussed above was classified as a discontinued operation 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 $1.0 million, $6.4 million and $16.1 million for the years ended December 31, 2003, 2002 and 2001, respectively.

SPC Sale of Assets

SPC was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC’s business activities have included the development of a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (Long Haul Assets) and the development of Metro Area Networks (MAN) in Las Vegas and Reno, Nevada.

In keeping with management’s strategy to focus on its core utility business, SPR sold SPC’s MAN assets on June 30, 2004.

Management is also pursuing the disposal of SPC’s Long Haul Assets as part of a settlement with Touch America and Sierra Touch America as part of their bankruptcy proceedings. The settlement stipulates that SPC will pay $10 million to STA and grant STA three ducts plus SPC’s portion of fiber in the main cable. Upon this payment and after satisfaction of other obligations all amounts remaining due on the $35 million promissory note shall be deemed paid and satisfied. The settlement also includes resolution of the lawsuit discussed in Note 15, Commitments and Contingencies, Litigation Contingencies, Touch America and Sierra Touch America LLC. The settlement also gives SPC title to the one remaining duct, of which SPC had previously entered into a contract to sale. The settlement between STA and various mechanic liens are expected to be finalized within one year. To the extent the final sales price differs from our estimate, an additional adjustment will be made accordingly.

The assets and liabilities associated with the discontinued operation of SPC and e-three are segregated on the consolidated balance sheets at December 31, 2003 and December 31, 2002. Pre-tax loss for SPC was $38 million, $8.6 million and $4.0 million for the years ending December 31, 2003, 2002 and 2001, respectively. Revenues for SPC were $1.6 million $700,000 and $274,000 for the years ending December 31, 2003, 2002 and 2001, respectively. The carrying amount of major asset and liability classifications are as follows: (In Thousands)


	SPC		SPC		E-Three		Total
	December 31, 2003		December 31, 2002		December 31, 2002		December 31, 2002
Investments and other property, net	$	36,511	$	68,352	$	9,488	$	77,840
Cash and cash equivalents		—		—		1,322		1,322
Accounts receivable		—		—		111		111
Materials and supplies		—		—		492		492
Current assets- Other		3,561		3,009		62		3,071
Goodwill		—		—		470		470
Deferred federal income taxes		—		—		731		731
Deferred charges- Other		—		—		186		186

Assets of Discontinued Operations	$	40,072	$	71,361	$	12,862	$	84,223

Long-term debt	$	—	$	31,315	$	—	$	31,315
Current maturities of long-term debt		19,666		—		68		68
Accounts payable		—		—		675		675
Accrued salaries and benefits		—		—		30		30
Current Liabilities		10,995		11,067		—		11,067
Deferred credits- Other		5,205		3,620		14		3,634

Liabilities of Discontinued Operations	$	35,866	$	46,003	$	787	$	46,789

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 4 of Notes to Financial Statements, 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.

Revenue from operations of the water business for the year ended December 31, 2001, was $23 million. 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 for the year ended December 31, 2001. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying consolidated statements of operations.

Other Property Disposals

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

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

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

Sierra Pacific Communications

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

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

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

This evaluation was conducted in conformance with the guidelines of SFAS No. 144, and also considered factors such as the anticipated liquidation of Sierra Touch America LLC assets, resulting in significant changes in business climate and projected discounted cash flows from the assets. SPC evaluated its MAN assets using projected discounted cash flows. The evaluation factored the undiscounted cash flows from current and projected sales contracts and continued operating expenses over the approximate 18-year remaining life of the assets and then discounted those cash flows to the end of the current reporting period. SPC evaluated its long haul network assets based in part on a pending sale for a portion of the long haul network assets currently under construction and in part by prices for similar assets adjusted for the market factors that resulted from the Touch America bankruptcy discussed above.

NOTE 20. 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 in thousands except per share amounts)

SIERRA PACIFIC RESOURCES


	Quarter Ended (9)
	March 31, 2003(1)(8)			June 30, 2003(8)			September 30, 2003(8)			December 31, 2003
Operating Revenues	$	602,512		$	666,251		$	904,347		$	614,433
Operating Income (loss)	$	46,824		$	6,193		$	165,147		$	53,300	(7)
Income (loss) from continuing operations	$	(8,307	)(3)	$	(188,311	)(5)	$	109,978	(6)	$	(17,520	)
Loss from discontinued operations	$	(1,937	)	$	(27,965	)	$	(1,231	)	$	(1,336	)
Earnings (loss) applicable to common stock	$	(11,219	)	$	(217,251	)	$	107,772		$	(19,831	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(0.07	)	$	(1.60	)	$	0.41		$	(0.15	)
From discontinued operations	$	(0.02	)	$	(0.24	)	$	(0.01	)	$	(0.01	)
Earnings (loss) applicable to common stock	$	(0.10	)	$	(1.11	)	$	0.39		$	(0.17	)


	Quarter Ended (9)
	March 31, 2002			June 30, 2002			September 30, 2002			December 31, 2002
Operating Revenues	$	636,813		$	700,350		$	1,017,199		$	630,242
Operating Income (loss)	$	(229,913	)(2)	$	20,967	(4)	$	143,711		$	37,726
Income (loss) from continuing operations	$	(302,044	)	$	(39,790	)	$	81,494		$	(34,639	)
(Loss) from discontinued operations	$	(897	)	$	(1,151	)	$	(1,145	)	$	(3,883	)
Earnings (loss) applicable to common stock	$	(305,482	)	$	(41,916	)	$	79,374		$	(39,497	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(2.96	)	$	(0.39	)	$	0.79		$	(0.34	)
From discontinued operations	$	(0.01	)	$	(0.02	)	$	(0.01	)	$	(0.04	)
Cumulative effect of change in accounting principle	$	(0.01	)	$	—		$	—		$	—
Earnings (loss) applicable to common stock	$	(2.98	)	$	(0.41	)	$	0.78		$	(0.39	)

(1) The amounts previously reported in the March 2003 10Q differ from the amounts currently reported due to 1st quarter revisions to reflect the discontinued operations presentation. Amounts were revised as shown in the tables below.

(2) Reflects the write-off of approximately $465 million of deferred energy costs and related carrying charges as a result of the PUCN decision in NPC’s deferred energy rate case. See Note 4, Regulatory Actions.

(3) During the first quarter of 2003 SPR recorded an unrealized gain of $16 million on the derivative instrument associated with the $300 million of convertible debt discussed in Note 11, Derivatives and Hedging Activities.

(4) Operating results were negatively affected by the write-off of $53 million of SPPC’s disallowed energy costs.

(5) Income from continuing operations was negatively affected by an unrealized loss of $124 million on the derivative instrument associated with the $300 million of convertible debt discussed in Note 11, Derivatives and Hedging Activities and loss due to the recognition of asset impairments of $33 million.

(6) Income from continuing operations was affected by an unrealized gain of $61.5 million on the derivative instrument associated with the $300 million of convertible debt as discussed in Note 11, Derivatives and Hedging Activities and higher interest cost that included the recognition of $40.2 million in interest as a result of the Bankruptcy Court judgment regarding Enron. See Note 15 of Notes to Financial Statements, Commitments and Contingencies.

(7) In the fourth quarter of 2003, SPR recognized charges of approximately $6.3 million (pretax) and $4.0 million (net of tax) from the correction of errors related to prior years (2000-2002) which were determined to be immaterial to the respective prior periods.

(8) On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010 (see Note 8, Long-Term Debt). In connection with these Notes, the conversion option, which was treated as a cash-settled written-call option, was separated from the debt and accounted for separately as a derivative instrument. The change in the fair value of the option was recognized during 2003 in SPR’s financial statements as an unrealized gain/loss on the derivative instrument. SPR also recorded deferred tax expense or benefit during the first three quarters of 2003, on the unrealized gain/loss, based on its belief that the change was a temporary difference. Additionally, as a result of the bifurcation of the conversion option from the Notes, the carrying value of the Convertible Notes at issuance was approximately $228 million with an effective interest rate of 12.5%. SPR began accreting the difference between the stated value of the Notes ($300 million) and the carrying value to interest expense on a monthly basis over the life of the issuance. SPR recorded current tax expense on the accretion of the interest expense.

Subsequent to the issuance of its interim financial statements for the first three quarters of 2003, SPR determined that the change in the fair value of the conversion option and the accretion expense of the debt discount resulting from the option at issuance date represent permanent differences and that SPR should not have recognized income taxes associated with these items.

As a result, the quarterly information presented herein has been restated from the amounts reported with SPR’s interim financial statements for the first three quarters of 2003 to remove $5.6 million of deferred tax expense, $43.2 million of deferred tax benefit and $21.5 million of deferred tax expense associated with the change in the fair value of the option for the quarters ended March 31, 2003, June 30, 2003 and September 30, 2003, respectively and has removed $0.3 million, $0.6 million and $0.6 million of current tax expense associated with the accretion expense related to the conversion option for the quarters ended March 31, 2003, June 30, 2003 and September 30, 2003 respectively. See revised quarterly data below.

(9) The amounts previously reported differ from the amounts currently reported due to revisions to reflect the discontinued operations presentation of SPC. See Note 19. Amounts were revised as shown in the tables below.


	As Originally			Adjustment for			Adjustment for
	Reported March			Disc Ops - e-			Convertible			Adjustment for			Revised
	31, 2003			three			Notes			Disc. Ops SPC			Balance
Operating Revenues	$	602,962		$	(152	)	$	—		$	(298	)	$	602,512
Operating Income (loss)	$	45,797		$	1,039		$	(295	)	$	283		$	46,824
Income (loss) from continuing operations	$	(15,523	)	$	1,008		$	5,279		$	929		$	(8,307	)
Loss from discontinued operations	$	—		$	(1,008	)	$	—		$	(929	)	$	(1,937	)
Earnings (loss) applicable to common stock	$	(16,498	)	$	—		$	5,279		$	—		$	(11,219	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(0.14	)	$	0.01		$	0.05		$	0.01		$	(0.07	)
From discontinued operations	$	—		$	(0.01	)	$	—		$	(0.01	)	$	(0.02	)
Earnings (loss) applicable to common stock	$	(0.15	)	$	—		$	0.05		$	—		$	(0.10	)


	As Originally
	Reported June 30,			Adjustment for			Adjustment for Disc.
	2003(8)			Convertible Notes			Ops SPC			Revised Balance
Operating Revenues	$	666,626		$	—		$	(375	)	$	666,251
Operating Income (loss)	$	(14,937	)	$	(605	)	$	21,735		$	6,193
Income (loss) from continuing operations	$	(166,658	)	$	(43,831	)	$	22,178		$	(188,311	)
Loss from discontinued operations	$	(5,787	)	$	—		$	(22,178	)	$	(27,965	)
Earnings (loss) applicable to common stock	$	(173,420	)	$	(43,831	)	$	—		$	(217,251	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(1.42	)	$	(0.37	)	$	0.19		$	(1.60	)
From discontinued operations	$	(0.05	)	$	—		$	(0.19	)	$	(0.24	)
Earnings (loss) applicable to common stock	$	(1.48	)	$	0.37		$	—		$	(1.11	)


	As Originally
	Reported			Adjustment for
	September 30,			Convertible			Adjustment for			Revised
	2003(8)			Notes			Disc. Ops SPC			Balance
Operating Revenues	$	904,877		$	—		$	(530	)	$	904,347
Operating Income (loss)	$	165,444		$	(624	)	$	327		$	165,147
Income (loss) from continuing operations	$	88,301		$	20,905		$	772		$	109,978
Loss from discontinued operations	$	(459	)	$	—		$	(772	)	$	(1,231	)
Earnings (loss) applicable to common stock	$	86,867		$	20,905		$	—		$	107,772
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	0.29		$	0.11		$	0.01		$	0.41
From discontinued operations	$	—		$	—		$	(0.01	)	$	(0.01	)
Earnings (loss) applicable to common stock	$	0.28		$	0.11		$	—		$	0.39


				Adjustment for Disc. Ops
	December 31,2003			SPC			Revised Balance
Operating Revenues	$	614,845		$	(412	)	$	614,433
Operating Income (loss)	$	52,429		$	871		$	53,300
Income (loss) from continuing operations	$	(18,857	)	$	1,335		$	(17,520	)
Loss from discontinued operations	$	—		$	(1,337	)	$	(1,336	)
Earnings (loss) applicable to common stock	$	(19,831	)	$	—		$	(19,831	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(0.16	)	$	0.01		$	(0.15	)
From discontinued operations	$	—		$	(0.01	)	$	(0.01	)
Earnings (loss) applicable to common stock	$	(0.17	)	$	—		$	(0.17	)


	As Originally Reported			Adjustment for
	March 31, 2002			Disc. Ops SPC			Revised Balance
Operating Revenues		636,934		$	(121	)		636,813
Operating Income (loss)		(230,638	)	$	725			(229,913	)
Income (loss) from continuing operations		(302,769	)	$	725			(302,044	)
(Loss) from discontinued operations		(172	)	$	(725	)		(897	)
Earnings (loss) applicable to common stock		(305,482	)		0			(305,482	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations		(2.97	)	$	0.01			(2.96	)
From discontinued operations		(0.00	)	$	(0.01	)		(0.01	)
Cumulative effect of change in accounting principle		(0.01	)	$	—			(0.01	)
Earnings (loss) applicable to common stock		2.98		$	—			2.98


	As Originally
	Reported June 30,			Adjustment for
	2002			Disc. Ops SPC			Revised Balance
Operating Revenues		700,524		$	(174	)		700,350
Operating Income (loss)		20,415		$	552			20,967
Income (loss) from continuing operations		(40,350	)	$	560			(39,790	)
(Loss) from discontinued operations		(591	)	$	(560	)		(1,151	)
Earnings (loss) applicable to common stock		(41,916	)					(41,916	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(0.40	)	$	0.01			(0.39	)
From discontinued operations	$	(0.01	)	$	(0.01	)		(0.02	)
Cumulative effect of change in accounting principle	$	—		$	—		$	—
Earnings (loss) applicable to common stock	$	(0.41	)	$	—			(0.41	)


	As Originally
	Reported September			Adjustment for Disc.
	30, 2002			Ops SPC			Revised Balance
Operating Revenues	$	1,017,371		$	(172	)	$	1,017,199
Operating Income (loss)	$	143,272		$	439		$	143,711
Income (loss) from continuing operations	$	80,363		$	1,131		$	81,494
(Loss) from discontinued operations	$	(14	)	$	(1,131	)	$	(1,145	)
Earnings (loss) applicable to common stock	$	79,374					$	79,374
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	0.78		$	0.01		$	0.79
From discontinued operations	$	—		$	(0.01	)	$	(0.01	)
Cumulative effect of change in accounting principle	$	—		$	—		$	—
Earnings (loss) applicable to common stock	$	0.78		$	—		$	0.78

NEVADA POWER


	Quarter Ended
	March 31, 2003			June 30, 2003			September 30, 2003			December 31, 2003
Operating Revenues	$	331,652		$	425,512		$	639,661		$	359,321
Operating Income (loss)	$	17,413		$	10,484	(2)	$	127,737		$	28,099
NET INCOME (LOSS)	$	(15,246	)	$	(22,192	)	$	62,524	(3)	$	(5,809	)


	Quarter Ended
	March 31, 2002			June 30, 2002		September 30, 2002		December 31, 2002
Operating Revenues	$	356,272		$	477,059	$	712,536	$	355,167
Operating Income (loss)	$	(260,759	)(1)	$	30,162	$	109,183	$	17,411
NET INCOME (LOSS)	$	(300,984	)	$	5,655	$	79,304	$	(19,045	)

(1)		Reflects the write-off of approximately $465 million of deferred energy costs and related carrying charges as a result of the PUCN decision in NPC’s deferred energy rate case. See Note 4, Regulatory Actions

(2)		Reflects the write-off of $46 million in May 2003 of disallowed deferred energy costs.

(3)		Reflects the charge of $27.8 million of interest cost as a result of the Bankruptcy Court judgment regarding Enron as discussed in Note 15, Commitments and Contingencies.

SIERRA PACIFIC POWER


	Quarter Ended
	March 31, 2003		June 30, 2003			September 30, 2003			December 31, 2003
Operating Revenues	$	270,071	$	240,899		$	264,407		$	254,489
Operating Income (loss)	$	23,820	$	(8,050	)(2)	$	32,588		$	20,208
NET INCOME (LOSS)	$	3,998	$	(27,955	)	$	(317	)(3)	$	999
Earnings (loss) applicable to common stock	$	3,023	$	(28,930	)	$	(1,292	)	$	24


	Quarter Ended
	March 31, 2002		June 30, 2002			September 30, 2002		December 31, 2002
Operating Revenues	$	279,837	$	222,668		$	304,193	$	274,336
Operating Income (loss)	$	24,934	$	(14,818	)(1)	$	30,021	$	15,155
NET INCOME (LOSS)	$	10,944	$	(33,951	)	$	13,543	$	(4,504	)
Earnings (loss) applicable to common stock	$	9,969	$	(34,926	)	$	12,568	$	(5,479	)

(1)		Operating results were negatively affected by the write-off of $53 million of SPPC’s disallowed energy costs.

(2)		Reflects the write-off of $45 million in June 2003 of disallowed deferred energy costs.

(3)		Reflects the charge of $12.4 million of interest costs as a result of the Bankruptcy Court judgment regarding Enron as discussed in Note 15, Commitments and Contingencies.


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

1-8788	SIERRA PACIFIC RESOURCES P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011	88-0198358


				Not required

		(b)		Pro forma financial information

				Not required

		(c)		Exhibits

				Exhibit 12.1 Ratio of Earnings To Fixed Charges
				Exhibit 23.1 Consent of Independent Registered Public Accounting Firm

	•		whether there will be any further requirements to pay the judgment of the Bankruptcy Court overseeing Enron’s bankruptcy proceeding in favor of Enron or to provide further cash collateral, to secure the stay of the judgment against the Utilities pending further appeal,

	•		whether the Utilities will be able to recover regulatory assets in their current and future rate cases, especially previously incurred deferred fuel and purchased power costs, and to provide sufficient revenues to support their operations,

	•		whether the Utilities will have sufficient liquidity and the ability in light of certain restrictions to provide dividends to SPR, and

	•		whether SPR and the Utilities will be able to successfully refinance maturing long-term debt and secure additional liquidity necessary to support their operations, including the purchase of fuel and power.

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

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

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

•		Maintain the currently effective Base Tariff Energy Rate.

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

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

•		SPPC and the Bureau of Consumer Protection agreed to file a motion to dismiss the civil lawsuits filed in relation to the 2002 SPPC deferred energy case.

(1)		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

(2)		the debt incurred is specifically permitted under the terms of the applicable Notes or Bond, 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, or

(3)		in the case of the Series G Notes and the Series H Bond, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 IRP.

(1)		.650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003,

(2)		.625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and

(3)		.600 to 1.0 for the fiscal quarter ended March 31, 2005 and for fiscal quarter thereafter.

(1)		1.75 to 1.00 for the fiscal quarters ended December 31, 2002, March 31, 2003, and June 30, 2003,

(2)		1.85 to 1.0 for the fiscal quarter ended September 30, 2003,

(3)		2.00 to 1.0 for the fiscal quarter ended December 30, 2003,

(4)		2.25 to 1.0 for the fiscal quarter ended March 31, 2004,

(5)		2.40 to 1.0 for the fiscal quarter ended June 30, 2004,

(6)		2.70 to 1.0 for the fiscal quarter ended September 30, 2004, and

(7)		3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter.

(1)		76.7073 shares of Common Stock plus an amount of cash equal to the then market value of 142.4564 shares of SPR Common Stock, subject to adjustment upon the occurrence of certain dilution events; or

(2)		219.1637 shares of SPR Common Stock, subject to adjustment upon the occurrence of certain dilution events.

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

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

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

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

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

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

	•		the total amount of such dividends is less than:

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

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

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

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

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

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

	•		SPPC’s Term Loan Agreement dated October 30, 2002, as amended, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s PIES) provided that those payments do not exceed $90 million, $80 million, and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004, and 2005, respectively. SPPC’s General and Refunding Mortgage Bond, Series E, General and Refunding Mortgage Notes, Series F and General and Refunding Mortgage Note, Series G, contain the same dividend restriction as the Term Loan Agreement.

			The Term Loan Agreement, the Series E Bond, the Series F Notes and the Series G Note, also permit SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the applicable financing agreement or security, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the such financing agreement or securities, do not exceed the sum of:

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

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

	•		On December 17, 2003, the PUCN issued an order in connection with its authorization of the issuance of short-term debt securities by NPC and SPPC. The PUCN order, for Dockets 03-10022 and 03-10023, permits NPC and SPPC to dividend an aggregate of $70 million per year to SPR through December 31, 2005. The PUCN order also provides that the dividend limitation may be reviewed in a subsequent application to grant short-term debt authority and that, in the event that exigent circumstances are experienced in the interim, either NPC or SPPC may petition the PUCN to review the dollar limitation.

	•		The Utilities are subject to the provision of the Federal Power Act, as applied to their particular circumstance that states that dividends cannot be paid out of funds that are properly included in their capital account. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

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

(1)		The amounts previously reported in the March 2003 10Q differ from the amounts currently reported due to 1st quarter revisions to reflect the discontinued operations presentation. Amounts were revised as shown in the tables below.

(2)		Reflects the write-off of approximately $465 million of deferred energy costs and related carrying charges as a result of the PUCN decision in NPC’s deferred energy rate case. See Note 4, Regulatory Actions.

(3)		During the first quarter of 2003 SPR recorded an unrealized gain of $16 million on the derivative instrument associated with the $300 million of convertible debt discussed in Note 11, Derivatives and Hedging Activities.

(4)		Operating results were negatively affected by the write-off of $53 million of SPPC’s disallowed energy costs.

(5)		Income from continuing operations was negatively affected by an unrealized loss of $124 million on the derivative instrument associated with the $300 million of convertible debt discussed in Note 11, Derivatives and Hedging Activities and loss due to the recognition of asset impairments of $33 million.

(6)		Income from continuing operations was affected by an unrealized gain of $61.5 million on the derivative instrument associated with the $300 million of convertible debt as discussed in Note 11, Derivatives and Hedging Activities and higher interest cost that included the recognition of $40.2 million in interest as a result of the Bankruptcy Court judgment regarding Enron. See Note 15 of Notes to Financial Statements, Commitments and Contingencies.

(7)		In the fourth quarter of 2003, SPR recognized charges of approximately $6.3 million (pretax) and $4.0 million (net of tax) from the correction of errors related to prior years (2000-2002) which were determined to be immaterial to the respective prior periods.

(8)		On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010 (see Note 8, Long-Term Debt). In connection with these Notes, the conversion option, which was treated as a cash-settled written-call option, was separated from the debt and accounted for separately as a derivative instrument. The change in the fair value of the option was recognized during 2003 in SPR’s financial statements as an unrealized gain/loss on the derivative instrument. SPR also recorded deferred tax expense or benefit during the first three quarters of 2003, on the unrealized gain/loss, based on its belief that the change was a temporary difference. Additionally, as a result of the bifurcation of the conversion option from the Notes, the carrying value of the Convertible Notes at issuance was approximately $228 million with an effective interest rate of 12.5%. SPR began accreting the difference between the stated value of the Notes ($300 million) and the carrying value to interest expense on a monthly basis over the life of the issuance. SPR recorded current tax expense on the accretion of the interest expense.

		Subsequent to the issuance of its interim financial statements for the first three quarters of 2003, SPR determined that the change in the fair value of the conversion option and the accretion expense of the debt discount resulting from the option at issuance date represent permanent differences and that SPR should not have recognized income taxes associated with these items.

		As a result, the quarterly information presented herein has been restated from the amounts reported with SPR’s interim financial statements for the first three quarters of 2003 to remove $5.6 million of deferred tax expense, $43.2 million of deferred tax benefit and $21.5 million of deferred tax expense associated with the change in the fair value of the option for the quarters ended March 31, 2003, June 30, 2003 and September 30, 2003, respectively and has removed $0.3 million, $0.6 million and $0.6 million of current tax expense associated with the accretion expense related to the conversion option for the quarters ended March 31, 2003, June 30, 2003 and September 30, 2003 respectively. See revised quarterly data below.

(9)		The amounts previously reported differ from the amounts currently reported due to revisions to reflect the discontinued operations presentation of SPC. See Note 19. Amounts were revised as shown in the tables below.


	Provision for Uncollectible Accounts
Balance at January 1, 2001	$	13,194
Provision charged to income(1)		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

Balance at January 1, 2003	$	44,184
Provision charged to income		26,858
Amounts written off, less recoveries		(26,125	)

Balance at December 31, 2003	$	44,917


		Sierra Pacific Resources (Registrant)

Date: August 12, 2004	By:	/s/ John E. Brown

		John E. Brown
		Vice President and Controller


	Year Ended December 31,
Amounts in 000’s	2003			2002			2001			2000			1999
EARNINGS AS DEFINED:
Income (Loss) From Continuing Operations After Interest Charges	$	(104,160	)	$	(294,979	)	$	35,818		$	(45,264	)	$	50,091
Income Taxes		(44,207	)		(161,191	)		14,218			(30,193	)		26,570

Income (Loss) From Continuing Operations before Income Taxes		(148,367	)		(456,170	)		50,036			(75,457	)		76,661
Fixed Charges		388,565			299,824			243,874			209,937			133,364
Capitalized Interest		(5,976	)		(5,270	)		(2,801	)		(10,634	)		(8,000	)
Preferred Stock Dividend Requirement		(6,000	)		(6,000	)		(5,692	)		(5,383	)		(3,385	)

Total	$	228,222		$	(167,616	)	$	285,417		$	118,463		$	198,640

FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)	$	382,565		$	293,824		$	238,182		$	204,554		$	129,979
Preferred Stock Dividend Requirement		6,000			6,000			5,692			5,383			3,385

Total	$	388,565		$	299,824		$	243,874		$	209,937		$	133,364

RATIO OF EARNINGS TO FIXED CHARGES								1.17						1.49
DEFICIENCY	$	160,343		$	467,440		$	—		$	91,474		$	—