NEVADA POWER CO - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)

x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 2004


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


Commission File	Registrant, Address of	I.R.S. employer	State of
Number	Principal Executive Offices and Telephone Number	Identification Number	Incorporation
1-08788	SIERRA PACIFIC RESOURCES	88-0198358	Nevada
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

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

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

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

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

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


Class		Outstanding at August 6, 2004
Common Stock, $1.00 par value of Sierra Pacific Resources		117,330,107 Shares

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

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

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements (Unaudited)

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30,		December 31,
	2004		2003
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,469,901	$	6,353,399
Less accumulated provision for depreciation		2,003,397		1,953,271

		4,466,504		4,400,128
Construction work-in-progress		149,423		242,522

		4,615,927		4,642,650

Investments and other property, net		73,429		73,130

Current Assets:
Cash and cash equivalents		49,869		181,757
Restricted cash and investments (Note 1)		99,373		54,705
Accounts receivable less allowance for uncollectible accounts:
2004-$45,054; 2003-$44,917		368,828		301,322
Deferred energy costs — electric (Note 1)		93,655		295,677
Deferred energy costs — gas (Note 1)		1,408		1,358
Materials, supplies and fuel, at average cost		75,072		79,525
Risk management assets		26,846		22,099
Accumulated deferred income tax		3,822		—
Deposits and prepayments for energy		84,148		63,847
Other		27,066		33,016

		830,087		1,033,306

Deferred Charges and Other Assets:
Goodwill (Note 11)		22,877		309,971
Deferred energy costs — electric		624,022		497,905
Regulatory tax asset		315,498		155,547
Other regulatory assets (Note 1)		493,880		142,507
Risk management regulatory assets — net (Note 8)		416		14,283
Unamortized debt issuance expense		62,924		50,842
Other		101,505		103,545

		1,621,122		1,274,600

Assets of Discontinued Operations (Note 12)		36,552		40,072

	$	7,177,117	$	7,063,758

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	1,346,671	$	1,435,394
Preferred stock		50,000		50,000
Long-term debt		3,840,037		3,579,674

		5,236,708		5,065,068

Current Liabilities:
Short-term borrowings		—		25,000
Current maturities of long-term debt		8,236		218,970
Accounts payable		182,892		165,936
Accrued interest		65,882		59,592
Dividends declared		973		968
Accrued salaries and benefits		29,062		24,444
Deferred taxes		—		106,478
Risk management liabilities (Note 8)		6,158		16,540
Accrued income taxes		7,147		8,077
Contract termination liabilities (Note 9)		340,839		338,704
Other current liabilities		39,537		29,088

		680,726		993,797

Commitments and Contingencies (Note 9) Deferred Credits and Other Liabilities:
Deferred federal income taxes		531,072		298,457
Deferred investment tax credit		43,696		45,329
Regulatory tax liability		39,938		41,877
Customer advances for construction		134,517		126,506
Accrued retirement benefits		133,344		112,075
Risk management regulatory liability — net (Note 8)		7,345		—
Contract termination liabilities (Note 9)		36,291		45,766
Regulatory liabilities (Note 1)		223,379		218,158
Other		73,142		80,859

		1,222,724		969,027

Liabilities of Discontinued Operations (Note 12)		36,959		35,866

	$	7,177,117	$	7,063,758

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
				As Revised (Note 1)						As Revised (Note 1)
OPERATING REVENUES:
Electric	$	652,350		$	630,538		$	1,180,724		$	1,167,643
Gas		21,879			35,873			81,355			100,491
Other		3,191			(160	)		3,458			629

		677,420			666,251			1,265,537			1,268,763

OPERATING EXPENSES:
Operation:
Purchased power		263,266			280,803			456,757			487,238
Fuel for power generation		114,109			115,469			217,266			195,682
Gas purchased for resale		14,482			27,865			62,399			70,199
Deferred energy costs disallowed		—			90,964			1,586			90,964
Deferral of energy costs — electric — net		38,942			18,683			86,831			102,870
Deferral of energy costs — gas — net		1,376			1,020			(31	)		11,823
Impairment of goodwill		—			—			11,695			—
Other		90,162			86,430			163,251			157,789
Maintenance		22,216			22,103			47,104			40,827
Depreciation and amortization		52,129			46,705			102,066			92,348
Taxes:
Income tax benefit		(5,835	)		(41,550	)		(27,897	)		(56,604	)
Other than income		11,839			11,566			23,690			22,611

		602,686			660,058			1,144,717			1,215,747

OPERATING INCOME		74,734			6,193			120,820			53,016
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		1,192			1,084			2,565			2,844
Interest accrued on deferred energy		5,981			6,823			12,530			14,458
Disallowed merger costs		—			—			(5,890	)		—
Disallowed plant costs		(47,092	)		—			(47,092	)		—
Other income		8,405			6,716			17,044			13,211
Other expense		(3,105	)		(3,268	)		(6,230	)		(6,999	)
Income (taxes) benefit		12,356			(3,233	)		10,798			(6,077	)
Unrealized loss on derivative instrument		—			(123,503	)		—			(107,578	)

		(22,263	)		(115,381	)		(16,275	)		(90,141	)

Total Income (Loss) Before Interest Charges		52,471			(109,188	)		104,545			(37,125	)
INTEREST CHARGES:
Long-term debt		85,719			70,814			161,179			142,676
Other		9,361			9,439			30,948			19,704
Allowance for borrowed funds used during construction		(1,667	)		(1,131	)		(3,840	)		(2,887	)

		93,413			79,122			188,287			159,493

LOSS FROM CONTINUING OPERATIONS		(40,942	)		(188,310	)		(83,742	)		(196,618	)
DISCONTINUED OPERATIONS:
Loss from discontinued operations (net of income taxes of $1,565, $15,248, $1,928 and $16,039, respectively)		(2,967	)		(27,965	)		(3,642	)		(29,902	)

NET LOSS		(43,909	)		(216,275	)		(87,384	)		(226,520	)
Preferred stock dividend requirements of subsidiary		975			975			1,950			1,950

LOSS APPLICABLE TO COMMON STOCK	$	(44,884	)	$	(217,250	)	$	(89,334	)	$	(228,470	)

Amount per share — basic and diluted Loss from continuing operations	$	(0.35	)	$	(1.61	)	$	(0.71	)	$	(1.72	)
Loss per share applicable to common stock	$	(0.38	)	$	(1.85	)	$	(0.76	)	$	(2.00	)
Weighted Average Shares of Common Stock Outstanding		117,279,506			117,144,486			117,259,726			114,337,776

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(87,384	)	$	(226,520	)
Non-cash items included in net loss:
Depreciation and amortization		102,066			92,683
Deferred taxes and deferred investment tax credit		(41,032	)		(81,598	)
AFUDC and capitalized interest		(6,405	)		(5,731	)
Amortization of deferred energy costs — electric		124,122			105,835
Amortization of deferred energy costs — gas		2,692			9,547
Deferred energy costs disallowed		1,586			90,965
Goodwill impairment		11,695			—
Unrealized loss on derivative instrument		—			107,578
Impairment of assets of discontinued operations		—			32,911
Loss on disposal of discontinued operations		2,346			8,851
Plant costs disallowed		47,092			—
Other non-cash		(44,410	)		(7,389	)
Changes in certain assets and liabilities:
Accounts receivable		(67,506	)		(18,365	)
Deferral of energy costs — electric		(49,803	)		(1,333	)
Deferral of energy costs — gas		(2,742	)		1,936
Materials, supplies and fuel		4,668			2,793
Other current assets		(14,353	)		(25,010	)
Accounts payable		16,956			(54,098	)
Payment to terminating suppliers		(60,351	)		—
Other current liabilities		20,251			18,808
Other assets		12,900			(24,938	)
Other liabilities		8,396			23,782
Net assets of discontinued operations		2,267			(9,727	)

Net Cash from Operating Activities		(16,949	)		40,980

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(184,615	)		(186,193	)
AFUDC and other charges to utility plant		6,405			5,731
Customer advances for construction		8,011			5,857
Contributions in aid of construction		12,428			10,699

Net cash used for utility plant		(157,771	)		(163,906	)
Investments in subsidiaries and other property — net		3,814			(11,775	)

Net Cash used by Investing Activities		(153,957	)		(175,681	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Increase /(Decrease) in short-term borrowings		(25,000	)		20,000
Change in restricted cash and investments		15,684			(49,708	)
Proceeds from issuance of long-term debt		575,000			300,000
Retirement of long-term debt		(525,371	)		(197,966	)
Sale of common stock, net of issuance cost		650			(986	)
Dividends paid		(1,945	)		(1,568	)

Net Cash from Financing Activities		39,018			69,772

Net Increase (Decrease) in Cash and Cash Equivalents		(131,888	)		(64,929	)
Beginning Balance in Cash and Cash Equivalents		181,757			192,064

Ending Balance in Cash and Cash Equivalents	$	49,869		$	127,135

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	183,908		$	142,095
Noncash Activities:
Exchange of Floating Rate Notes for SPR Common Stock	$	—		$	8,750
Exchange of Premium Income Equity Securities for SPR Common Stock	$	—		$	104,782
Transfer of Regulatory Asset (Note 11)	$	294,468		$	—

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30,		December 31,
	2004		2003
ASSETS
Utility Plant at Original Cost:
Plant in service	$	3,941,810	$	3,816,630
Less accumulated provision for depreciation		1,066,111		1,018,044

		2,875,699		2,798,586
Construction work-in-progress		99,191		109,148

		2,974,890		2,907,734

Investments and other property, net		36,667		36,312

Current Assets:
Cash and cash equivalents		13,449		144,897
Restricted cash (Note 1)		49,637		2,600
Accounts receivable less allowance for uncollectible accounts:
2004-$39,775; 2003-$40,297		255,136		167,296
Accounts receivable, affiliate companies		—		3,533
Deferred energy costs — electric (Note 1)		67,171		247,249
Materials, supplies and fuel, at average cost		41,826		41,076
Risk management assets (Note 8)		12,208		11,702
Deposits and prepayments for energy		50,901		39,794
Other		19,351		21,540

		509,679		679,687

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		477,864		371,305
Regulatory tax asset		201,146		102,282
Other regulatory assets (Note 1)		279,513		60,721
Risk management regulatory assets — net (Note 8)		416		3,109
Unamortized debt issuance expense		37,929		34,052
Other		15,510		15,557

		1,012,378		587,026

	$	4,533,614	$	4,210,759

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,350,686	$	1,174,645
Long-term debt		2,038,140		1,899,709

		3,388,826		3,074,354

Current Liabilities:
Current maturities of long-term debt		5,836		135,570
Accounts payable		129,727		107,812
Accounts payable, affiliated companies		3,321		—
Accrued interest		37,285		35,399
Accrued salaries and benefits		12,794		10,315
Deferred taxes		29,550		97,464
Risk management liabilities (Note 8)		3,986		5,266
Accrued income taxes		3,764		4,934
Contract termination liabilities (Note 9)		237,303		235,729
Other current liabilities		32,465		22,397

		496,031		654,886

Commitments and Contingencies (Note 9)
Deferred Credits and Other Liabilities:
Deferred federal income taxes		295,247		124,914
Deferred investment tax credit		19,457		20,272
Regulatory tax liability		15,125		15,776
Customer advances for construction		75,644		71,176
Accrued retirement benefits		16,051		5,825
Contract termination liabilities (Note 9)		34,413		43,916
Regulatory liabilities (Note 1)		146,560		147,887
Other		46,260		51,753

		648,757		481,519

	$	4,533,614	$	4,210,759

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
OPERATING REVENUES:
Electric	$	449,925		$	425,512		$	776,458		$	757,164
OPERATING EXPENSES:
Operation:
Purchased power		191,508			205,129			319,039			324,386
Fuel for power generation		60,312			67,910			109,667			114,447
Deferred energy costs disallowed		—			45,964			1,586			45,964
Deferral of energy costs-net		38,808			11,442			82,126			84,227
Other		50,913			51,675			90,635			92,215
Maintenance		16,790			15,650			36,746			29,187
Depreciation and amortization		29,991			26,714			58,730			52,621
Taxes:
Income tax expense / (benefit)		5,339			(16,274	)		(6,114	)		(26,822	)
Other than income		6,794			6,818			13,573			13,042

		400,455			415,028			705,988			729,267

OPERATING INCOME		49,470			10,484			70,470			27,897
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		625			483			1,282			1,641
Interest accrued on deferred energy		4,798			5,234			10,193			10,944
Disallowed merger costs		—			—			(3,961	)		—
Other income		5,389			4,136			11,129			7,591
Other expense		(1,487	)		(1,618	)		(2,928	)		(3,050	)
Income taxes		(3,057	)		(2,679	)		(5,045	)		(5,193	)

		6,268			5,556			10,670			11,933

Total Income Before Interest Charges		55,738			16,040			81,140			39,830
INTEREST CHARGES:
Long-term debt		37,683			32,838			74,834			66,850
Other		5,241			5,914			9,828			11,994
Allowance for borrowed funds used during construction		(776	)		(520	)		(1,706	)		(1,576	)

		42,148			38,232			82,956			77,268

NET INCOME/( LOSS)	$	13,590		$	(22,192	)	$	(1,816	)	$	(37,438	)

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(1,816	)	$	(37,438	)
Non-cash items included in net loss:
Depreciation and amortization		58,730			52,621
Deferred taxes and deferred investment tax credit		2,089			(21,632	)
AFUDC		(2,988	)		(3,217	)
Amortization of deferred energy costs		104,532			81,962
Deferred energy costs disallowed		1,586			45,965
Other non-cash		(27,425	)		(2,339	)
Changes in certain assets and liabilities:
Accounts receivable		(84,307	)		(44,664	)
Deferral of energy costs		(32,598	)		(8,679	)
Materials, supplies and fuel		(535	)		1,405
Other current assets		(8,918	)		(24,995	)
Accounts payable		25,236			(34,349	)
Escrow payment to terminating suppliers		(49,637	)		—
Other current liabilities		13,263			10,984
Other assets		5,968			(25,819	)
Other liabilities		(5,803	)		37,612

Net Cash from Operating Activities		(2,623	)		27,417

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(132,565	)		(122,671	)
AFUDC and other charges to utility plant		2,988			3,217
Customer advances for construction		4,468			3,525
Contributions in aid of construction		5,224			5,866

Net cash used for utility plant		(119,885	)		(110,063	)
Investments in subsidiaries and other property — net		(120	)		(13,734	)

Net Cash from Investing Activities		(120,005	)		(123,797	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings		—			20,000
Change in restricted cash and investments		2,600			3,850
Proceeds from issuance of long-term debt		140,000			—
Retirement of long-term debt		(131,303	)		(1,361	)
Dividends paid		(20,117	)		—

Net Cash from Financing Activities		(8,820	)		22,489

Net Decrease in Cash and Cash Equivalents		(131,448	)		(73,891	)
Beginning Balance in Cash and Cash Equivalents		144,897			95,009

Ending Balance in Cash and Cash Equivalents	$	13,449		$	21,118

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	81,435		$	67,401
Noncash Activities:
Transfer of Regulatory Asset (Note 11)	$	197,998		$	—

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30,		December 31,
	2004		2003
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,528,091	$	2,536,769
Less accumulated provision for depreciation		937,286		935,227

		1,590,805		1,601,542
Construction work-in-progress		50,232		133,374

		1,641,037		1,734,916

Investments and other property, net		893		916

Current Assets:
Cash and cash equivalents		15,810		20,859
Restricted cash (Note 1)		17,350		8,776
Accounts receivable less allowance for uncollectible accounts:
2004-$5,279; 2003-$4,620		112,153		133,595
Accounts receivable, affiliated companies		64,686		56,349
Deferred energy costs — electric (Note 1)		26,484		48,428
Deferred energy costs — gas (Note 1)		1,408		1,358
Materials, supplies and fuel, at average cost		33,260		38,449
Risk management assets (Note 8)		14,638		10,397
Deposits and prepayments for energy		33,247		24,053
Other		4,046		7,265

		323,082		349,529

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		146,158		126,600
Regulatory tax asset		114,352		53,265
Other regulatory assets (Note 1)		214,367		62,716
Risk management regulatory assets — net (Note 8)		—		11,174
Unamortized debt issuance expense		14,519		12,383
Other		9,349		10,970

		498,745		277,108

	$	2,463,757	$	2,362,469

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	663,764	$	593,771
Preferred stock		50,000		50,000
Long-term debt		995,296		912,800

		1,709,060		1,556,571

Current Liabilities:
Short-term borrowings		—		25,000
Current maturities of long-term debt		2,400		83,400
Accounts payable		33,100		40,731
Accrued interest		9,642		10,374
Dividends declared		973		968
Accrued salaries and benefits		13,588		11,775
Deferred taxes		8,283		25,726
Risk management liabilities (Note 8)		2,172		11,274
Accrued income taxes		3,206		3,009
Contract termination liabilities (Note 9)		103,536		102,975
Other current liabilities		5,710		4,120

		182,610		319,352

Commitments and Contingencies (Note 9)
Deferred Credits and Other Liabilities:
Deferred federal income taxes		293,137		231,274
Deferred investment tax credit		24,239		25,057
Regulatory tax liability		24,813		26,101
Customer advances for construction		58,873		55,330
Accrued retirement benefits		63,411		52,709
Risk management regulatory liability — net (Note 8)		7,345		—
Contract termination liabilities (Note 9)		1,878		1,850
Regulatory liabilities (Note 1)		76,819		70,271
Other		21,572		23,954

		572,087		486,546

	$	2,463,757	$	2,362,469

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
OPERATING REVENUES:
Electric	$	202,425		$	205,026		$	404,266		$	410,480
Gas		21,879			35,873			81,355			100,490

		224,304			240,899			485,621			510,970

OPERATING EXPENSES:
Operation:
Purchased power		71,758			75,674			137,718			162,852
Fuel for power generation		53,797			47,559			107,599			81,235
Gas purchased for resale		14,482			27,865			62,399			70,199
Deferred energy costs disallowed		—			45,000			—			45,000
Deferral of energy costs — electric — net		134			7,241			4,705			18,643
Deferral of energy costs — gas — net		1,376			1,020			(31	)		11,823
Other		32,891			31,625			63,702			60,838
Maintenance		5,426			6,453			10,358			11,640
Depreciation and amortization		22,138			19,961			43,336			39,667
Taxes:
Income taxes/(benefit)		(571	)		(18,298	)		305			(16,208	)
Other than income		4,981			4,849			9,996			9,511

		206,412			248,949			440,087			495,200

OPERATING INCOME (LOSS)		17,892			(8,050	)		45,534			15,770
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		567			601			1,283			1,203
Interest accrued on deferred energy		1,183			1,589			2,337			3,514
Disallowed merger costs		—			—			(1,929	)		—
Plant costs disallowed		(47,092	)		—			(47,092	)		—
Other income		896			1,035			1,756			2,100
Other expense		(1,242	)		(1,702	)		(2,555	)		(3,607	)
Income (taxes)/benefit		15,035			(476	)		15,358			(779	)

		(30,653	)		1,047			(30,842	)		2,431

Total Income (Loss) Before Interest Charges		(12,761	)		(7,003	)		14,692			18,201
INTEREST CHARGES:
Long-term debt		17,847			18,959			36,715			37,740
Other		2,470			2,604			4,627			5,729
Allowance for borrowed funds used during construction and capitalized interest		(891	)		(611	)		(2,134	)		(1,311	)

		19,426			20,952			39,208			42,158

NET LOSS		(32,187	)		(27,955	)		(24,516	)		(23,957	)
Preferred Dividend Requirements		975			975			1,950			1,950

Loss applicable to common stock	$	(33,162	)	$	(28,930	)	$	(26,466	)	$	(25,907	)

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	(24,516	)	$	(23,957	)
Non-cash items included in income (loss):
Depreciation and amortization		43,336			39,667
Deferred taxes and deferred investment tax credit		(18,772	)		(42,701	)
AFUDC		(3,417	)		(2,514	)
Amortization of deferred energy costs — electric		19,591			23,873
Amortization of deferred energy costs — gas		2,692			9,547
Deferred energy costs disallowed		—			45,000
Plant costs disallowed		47,092			—
Other non-cash		(7,410	)		(7,884	)
Changes in certain assets and liabilities:
Accounts receivable		13,105			25,048
Deferral of energy costs — electric		(17,205	)		7,346
Deferral of energy costs — gas		(2,742	)		1,936
Materials, supplies and fuel		5,189			1,386
Other current assets		(5,975	)		(2,255	)
Accounts payable		(7,631	)		(14,581	)
Escrow payment for terminating supplier		(10,715	)		—
Other current liabilities		2,868			2,897
Other assets		6,932			894
Other liabilities		13,699			(12,274	)

Net Cash from Operating Activities		56,121			51,428

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(52,050	)		(63,521	)
AFUDC and other charges to utility plant		3,417			2,514
Customer advances for construction		3,543			2,332
Contributions in aid of construction		7,203			4,832

Net cash used for utility plant		(37,887	)		(53,843	)
Disposal of subsidiaries and other property — net		24			(67	)

Net Cash from Investing Activities		(37,863	)		(53,910	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings		(25,000	)		—
Change in restricted cash and investments		2,141			2,979
Proceeds from issuance of long-term debt		100,000			—
Retirement of long-term debt		(98,503	)		(1,010	)
Dividends paid		(1,945	)		(1,944	)

Net Cash from Financing Activities		(23,307	)		25

Net Increase in Cash and Cash Equivalents		(5,049	)		(2,457	)
Beginning Balance in Cash and Cash Equivalents		20,859			88,910

Ending Balance in Cash and Cash Equivalents	$	15,810		$	86,453

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	41,486		$	40,791
Noncash Activities:
Transfer of Regulatory Asset (Note 11)	$	96,470		$	—

The accompanying notes are an integral part of the financial statements

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

In the opinion of the management of SPR, NPC, and SPPC, the accompanying unaudited interim consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2003 (the “2003 10-K”).

The results of operations and cash flows of SPR, NPC, and SPPC for the six months ended June 30, 2004, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

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

Revised Quarterly Information

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. In connection with these Notes, the conversion option, which was treated as a cash-settled written-call option, was considered separately 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 the issuance date represent permanent differences and that SPR should not have recognized income taxes associated with these items.

As a result, the June 30, 2003 information presented herein has been restated from the amounts reported in SPR’s interim financial statements for three and six months ended June 30, 2003 to remove $43.2 million and $37.6 million, respectively, of deferred tax benefit associated with the change in the fair value of the option for the three and six months ended June 30, 2003 and has removed $0.6 million and $0.9 million, respectively, of current tax expense associated with the accretion expense related to the conversion option. Also, the amounts previously reported in SPR’s Quarterly Report on Form 10-Q for the six and three months ended June 30, 2003 differ from the amounts currently reported due to revisions to reflect the

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

discontinued operations presentation of SPC. See Note 12 – Disposal of Assets. Amounts for the three months and six months ended were revised as shown in the table below (dollars in thousands):


	Three Months Ended
	June 30, 2003
				Adjustment for			Adjustment for
	As Originally			Convertible			Disc. Ops			Revised
	Reported			Notes			SPC			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	)	$	(43,830	)	$	22,178		$	(188,310	)
Loss from discontinued operations	$	(5,787	)	$	—		$	(22,178	)	$	(27,965	)
Earnings (loss) applicable to common stock	$	(173,420	)	$	(43,830	)	$	—		$	(217,250	)
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	)	$	—		$	(1.85	)


	Six Months Ended June 30, 2003
				Adjustment for			Adjustment for
	As Originally			Convertible			Disc. Ops			Revised
	Reported			Notes			SPC			Balance
Operating Revenues	$	1,269,436		$	—		$	(673	)	$	1,268,763
Operating Income (loss)	$	31,898		$	(900	)	$	22,018		$	53,016
Income (loss) from continuing operations	$	(181,173	)	$	(38,552	)	$	23,107		$	(196,618	)
Loss from discontinued operations	$	(6,795	)	$	—		$	(23,107	)	$	(29,902	)
Earnings (loss) applicable to common stock	$	(189,918	)	$	(38,552	)	$	—		$	(228,470	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(1.58	)	$	(0.34	)	$	0.20		$	(1.72	)
From discontinued operations	$	(0.06	)	$	—		$	(0.20	)	$	(0.26	)
Earnings (loss) applicable to common stock	$	(1.66	)	$	(0.34	)	$	—		$	(2.00	)

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are regulated by 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As a result of decisions on NPC’s and SPPC’s 2003 General Rate Case, (See Note 4 of the Condensed Notes to Consolidated Financial Statements, Regulatory Actions) Other Regulatory Assets changed significantly from the December 31, 2003 amounts. Presented below are the balances as of June 30, 2004, and treatment of each regulatory asset and the balances as of December 31, 2003 (dollars in thousands):

SIERRA PACIFIC RESOURCES
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF JUNE 30, 2004
		Receiving Regulatory Treatment								As of
						Pending				December 31,
	Remaining Amortization	Earning a		Not Earning		Regulatory		2004		2003
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total
Regulatory Assets
Early retirement and severance offers	Various thru 2004	$	—	$	1,249	$	—	$	1,249	$	2,497
Loss on reacquired debt	Term of Related Debt		32,846		—		—		32,846		30,123
Plant assets	Various thru 2031		42,496		7,397		—		49,893		3,414
Nevada divestiture costs	Thru 5/2012		35,267		—		—		35,267		35,164
Merger transition/transaction costs	Thru 5/2014		—		36,994		—		36,994		14,185
Merger severance/relocation	Thru 5/2014		—		20,888		—		20,888		21,375
Merger goodwill	Thru 5/2044		—		291,297		—		291,297		19,070
California restructure costs	Thru 2008		1,848		—		2,285		4,133		4,368
Conservation programs	Thru 2005		12,188		—		—		12,188		8,361
Variable rate mechanism deferral	Thru 10/2004		—		69		—		69		352
Other costs	Thru 2008		6,057		395		2,604		9,056		3,598

Total regulatory assets		$	130,702	$	358,289	$	4,889	$	493,880	$	142,507

Regulatory Liabilities
Cost of Removal	Various	$	188,664	$	—	$	—	$	188,664	$	174,717
Gain on Property Sales	Various thru 2007		31,314		630		—		31,944		39,312
SO2 Allowances	Various thru 2009		2,728		—		43		2,771		4,129

Total regulatory liabilities		$	222,706	$	630	$	43	$	223,379	$	218,158

NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF JUNE 30, 2004
DESCRIPTION		Receiving Regulatory Treatment								As of
	Remaining					Pending				December 31,
	Amortization	Earning a		Not Earning		Regulatory		2004		2003
	Period	Return		a Return		Treatment		Total		Total
Regulatory Assets
Loss on reacquired debt	Term of Related Debt	$	13,545	$	—	$	—	$	13,545	$	13,956
Nevada divestiture costs	Thru 3/2012		21,649		—		—		21,649		21,886
Merger transition/transaction costs	Thru 3/2014		—		25,882		—		25,882		7,652
Merger severance/relocation	Thru 3/2014		—		9,947		—		9,947		10,209
Merger Goodwill	Thru 3/2044		—		195,028		—		195,028		—
Conservation programs	Thru 2005		9,709		—		—		9,709		6,809
Other costs	Various thru 2008		2,796		187		770		3,753		209

Total regulatory assets		$	47,699	$	231,044	$	770	$	279,513	$	60,721

Regulatory Liabilities
Cost of Removal		$	111,890	$	—	$	—	$	111,890	$	104,446
Gain on Property Sales	Various thru 2007		31,312		630		—		31,942		39,312
SO2 Allowances	Various thru 2009		2,728		—		—		2,728		4,129

Total regulatory liabilities		$	145,930	$	630	$	—	$	146,560	$	147,887

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SIERRA PACIFIC POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF JUNE 30, 2004
		Receiving Regulatory Treatment								As of
	Remaining					Pending				December 31,
DESCRIPTION	Amortization	Earning a		Not Earning		Regulatory		2004		2003
	Period	Return		a Return		Treatment		Total		Total
Regulatory assets
Early retirement and severance offers	Various through 2004	$	—	$	1,249	$	—	$	1,249	$	2,497
Loss on reacquired debt	Term of Related Debt		19,301		—		—		19,301		16,167
Plant assets	Various through 2031		42,496		7,397		—		49,893		3,414
Nevada divestiture costs	Thru 5/2012		13,618		—		—		13,618		13,278
Merger transition/transaction costs	Thru 5/2014		—		11,112		—		11,112		6,533
Merger severance/relocation	Thru 5/2014		—		10,941		—		10,941		11,166
Merger goodwill	Thru 5/2044		—		96,269		—		96,269		—
California Restructure Costs	Thru 2008		1,848		—		2,285		4,133		4,368
Conservation Programs	Thru 2005		2,479		—		—		2,479		1,552
Variable rate mechanism deferral	Thru 10/2004		—		69		—		69		352
Other costs	Various through 2017		3,261		208		1,834		5,303		3,389

Total regulatory assets		$	83,003	$	127,245	$	4,119	$	214,367	$	62,716

Regulatory Liabilities
SO2 Allowances		$	—	$	—	$	43	$	43	$	—
Cost of Removal	Various		76,774		—		—		76,774		70,271
Gain on Property Sales	Thru 2005		2		—		—		2		—

Total regulatory liabilities		$	76,776	$	—	$	43	$	76,819	$	70,271

Deferral of Energy Costs

NPC and SPPC implemented deferred energy accounting on March 1, 2001. Beginning January 2004, the CPUC issued its decision which re-instituted the Energy Cost Adjustment (ECAC) mechanism for SPPC’s California electric business. The ECAC allows SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. See Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in NPC’s and SPPC’s 2003 10-K, for additional information regarding the implementation of deferred energy accounting by the Utilities.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following deferred energy costs were included in the consolidated balance sheets as of June 30, 2004 (dollars in thousands):


	June 30, 2004
	NPC		SPPC			SPPC			SPR
Description	Electric		Electric			Gas			Total
Unamortized balances approved for collection in current rates	$	169,633	$	25,448		$	(1,770	)	$	193,311
Unamortized balances approved for collection by PUCN in Docket No. 03-11019 effective April 1, 2004		89,014		—			—			89,014
Balances pending PUCN approval		—		42,398	(1)		3,357			45,755
Balances pending CPUC approval		—		1,605			—			1,605
Balances accrued since end of periods submitted for PUCN approval		46,349		19,159			(179	)		65,329
Claims for terminated supply contracts (2)		240,039		84,032			—			324,071

Total	$	545,035	$	172,642		$	1,408		$	719,085

Current Assets
Deferred energy costs — electric	$	67,171	$	26,484		$	—		$	93,655
Deferred energy costs — gas		—		—			1,408			1,408
Deferred Assets
Deferred energy costs — electric		477,864		146,158			—			624,022

Total	$	545,035	$	172,642		$	1,408		$	719,085

(1) Balance approved for collection on July 7, 2004.

(2) Amounts related to claims for terminated supply contracts are discussed in Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies.

Restricted Cash and Investments

At June 30, 2004, restricted cash and investments primarily consists of $32 million of cash to be used exclusively for debt service payments for SPR’s $300 million convertible notes, discussed in Note 8, Long-Term Debt, of Notes to Financial Statements in SPR’s 2003 10-K, an aggregate $60 million in cash collateral deposited by NPC and SPPC into escrow in connection with the stay of the Enron Judgment, as described in Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies, and the remaining amount consists of cash balances that SPR, NPC and SPPC are required to maintain to support their cash management activities due to their financial condition.

Stock Compensation Plans

At 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 in the 2003 10-K. SPR applies Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” in accounting for its stock option plans and in accordance with the disclosure only provisions of 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 loss applicable to common stock would have increased to the pro forma amounts indicated below (dollars in thousands, except per share amounts):

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2004			2003			2004			2003
Loss applicable to common stock, as reported	As reported	$	(44,884	)	$	(217,250	)	$	(89,334	)	$	(228,470	)
Add: Stock-based employee compensation expense credits included in reported net income, net of related tax effects	As reported		(56	)		125			268			25
Less: Total stock employee compensation expense credits determined under fair value based methods, net of related tax effects	Pro forma		(12	)		169			305			1,242

Pro forma loss applicable to common stock	Pro forma	$	(44,928	)	$	(217,294	)	$	(89,371	)	$	(229,687	)

Basic loss per share	As reported	$	(0.38	)	$	(1.85	)	$	(0.76	)	$	(2.00	)
	Pro forma	$	(0.38	)	$	(1.85	)	$	(0.76	)	$	(2.01	)
Diluted loss per share	As reported	$	(0.38	)	$	(1.85	)	$	(0.76	)	$	(2.00	)
	Pro forma	$	(0.38	)	$	(1.85	)	$	(0.76	)	$	(2.01	)

Recent Pronouncements

In December 2003, the FASB issued Interpretation No. 46, as 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, SPR, NPC and SPPC adopted FIN 46(R) for special purpose entities. As of March 31, 2004, SPR, NPC and SPPC adopted FIN 46(R) for all variable interest entities. To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with qualifying facilities, jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven qualifying facilities (QFs) with long-term purchase power contracts that are variable interests. However, the Utilities are not required at this time to consolidate these QFs under the scope exception provided for in FIN 46(R) related to the inability to obtain information necessary to (1) determine whether the entity is a variable interest entity, (2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3) perform the accounting required to consolidate the variable interest entity for which it is determined to be the primary beneficiary. The Utilities have requested financial information from these QFs but have not been successful in obtaining the information. The Utilities’ maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. The Utilities have not identified any other significant variable interests that require consolidation as of June 30, 2004.

FSP FAS 106-2

The FASB issued FASB Statement of Position (FSP) FAS 106-2 in May 2004 to provide guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, signed into law by the President on December 8, 2003 (the “Act”). This FSP FAS 106-2 supersedes FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, for which SPR elected to defer implementation due to the lack of definitive guidelines from the FASB and the Department of Health and Human Services. SPR had tentatively concluded that its prescription drug plan would qualify for the federal subsidy under this Act.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

its plan’s costs, the subsidy is included in measuring the costs of benefits attributable to current service. Therefore, the subsidy reduces service cost (as defined in paragraph 47 of SFAS 106) when it is recognized as a component of net periodic postretirement benefit cost. The FSP allows for either prospective recognition from the date of adoption or retroactive recognition by restating prior quarters for the effect of the change. The latter treatment will allow for the recognition of the cumulative effect of change on prior year’s financial statements, if material, but will not require statements to be reissued. The FSP is effective for the first interim or annual period beginning after June 15, 2004.

Final guidelines were issued by the Department of Health and Human Services on July 26, 2004, and SPR is continuing to evaluate the impact of this Act on its postretirement benefit expense. SPR’s current valuation of its APBO and net periodic benefit costs do not reflect the effects of the federal subsidy.

NOTE 2. LIQUIDITY MATTERS AND MANAGEMENT’S PLANS

Significant Uncertainties

As discussed in more detail in Note 2, Liquidity Matters and Management’s Plans, of Notes to Financial Statements in their 2003, 10-K, at December 31, 2003, SPR, NPC and SPPC were subject to significant uncertainties as follows:

• 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 have sufficient liquidity and the ability under certain restrictions to provide dividends to SPR;

• 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; and

• 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.

Since the date of the filing of the 2003 10-K, SPR and the Utilities have made significant progress towards resolving a number of the uncertainties described above. The following discussion describes those uncertainties as of August 6, 2004, and outlines actions taken by the companies and recent events affecting the uncertainties.

Enron Litigation

See Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies for further information regarding the Enron litigation.

On April 5, 2004, a hearing was held before the Bankruptcy Court overseeing the Enron bankruptcy proceedings to determine whether NPC and SPPC had the ability to post additional cash collateral into escrow in order to further stay the execution of Enron’s judgment against the Utilities. The parties entered into an agreement that provided for NPC to place an additional $25 million cash into the escrow account within 10 days of the order memorializing the stipulation, which amount would lower the principal amount of NPC’s General and Refunding Mortgage Bond currently held in escrow to secure a stay of the Judgment by a like amount. NPC paid the $25 million on April 16, 2004 as agreed upon. In addition, Enron agreed not to request any additional cash to be placed into escrow during the pendency of the Utilities’ appeal of the Judgment to the U.S. District Court of the Southern District of New York.

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. In the Utilities’ appeal, the Utilities seek reversal of the Judgment and contend that Enron is not entitled to recover termination charges under the contracts on various grounds including breach of contract, breach of solvency representation, fraud, misrepresentation, and manipulation of the energy markets and that the Bankruptcy Court erred in holding that the filed rate doctrine barred various claims which were purported to challenge the reasonableness of the rate. Enron filed a cross-appeal on the grounds that the amount of post-judgment interest should have been 12% per year instead of 1.21% as ordered by the Bankruptcy Court. The appeal has been fully briefed and oral argument was heard by the Court on May 28, 2004. The U.S. District Court has not yet ruled on this matter nor has it indicated when a decision may be rendered. The Utilities are unable to predict the outcome of their appeal of the Judgment.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. The FERC’s order is discussed further in Note 9 Commitments and Contigencies. The Utilities are unable to predict whether the FERC’s decision in the proceeding will affect their appeal of the Judgment or any subsequent appeals of the Judgment.

At June 30, 2004, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” are approximately $272 million and $105 million of charges, 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 June 30, 2004, are approximately $240 million and $84 million of charges, 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, the Utilities will pursue recovery of the payments through future deferred energy filings. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amounts not permitted would be charged as a current operating expense. A significant disallowance of these costs by the PUCN could have a material adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Financing, Liquidity and Other Matters

NPC and SPPC anticipate capital requirements for construction costs in 2004 will be approximately $473 million and $108 million, respectively, which the Utilities expect to finance with internally generated funds, including the recovery of deferred energy, and new secured debt. Through August 6, 2004, SPR, NPC and SPPC issued and/or refinanced maturing debt and secured revolving credit facilities in order to support their operations including purchasing power and supporting construction costs. See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt for details of the refinancings and the Utilities’ revolving credit facilities. The financings significantly alleviate the Utilities’ liquidity concerns; however, 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, or enter into additional liquidity facilities.

As discussed in the 2003 10-K, 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, on a stand-alone basis, had cash and cash equivalents of approximately $20 million at June 30, 2004, which does not include restricted cash and investments of approximately $32 million. The $32 million restricted cash and investments, represents collateral for payment of interest up to and including August 14, 2005 in connection with SPR’s 7.25% Convertible Notes due 2010. SPR paid approximately $42 million of debt service obligations on its existing debt securities as of June 30, 2004. SPR has approximately $36 million payable of debt service obligations remaining during 2004. Approximately $11 million of SPR’s remaining debt service obligations in 2004 will be satisfied with cash included in SPR’s Restricted Cash balance as discussed above. Currently, SPR expects to meet its remaining debt service obligations for 2004 of approximately $25 million 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 7 of the Condensed Notes to Consolidated Financial Statements, Dividend Restrictions for a discussion of the dividend restrictions applicable to the Utilities.

Regulatory Matters

On March 26, 2004, the PUCN issued its decisions on NPC’s 2003 General and Deferred Energy Rate Cases.

On May 27, 2004, and July 7, 2004, the PUCN issued its decisions on SPPC’s 2003 General Rate Case and 2004 Deferred Energy Rate Case.

See Note 4 of the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for details of these decisions.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Both NPC and SPPC are mandated by statute to file Deferred Energy Rate Cases at least once annually, and General Rate Cases at least once every two years. Management cannot predict the outcome of future General Rate Cases or Deferred Energy proceedings. Material disallowances, as a result of adverse decisions in future general or deferred rate proceedings, would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause additional downgrades of their securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties.

Business Strategies

SPR and the Utilities are addressing the uncertainties of the Enron litigation, SPR’s ability to meet its debt service obligations through dividends from its subsidiaries, and the outcome of future regulatory proceedings by focusing on the following business strategies:

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 anticipates that the Utilities would 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; however, there can be no assurances that either the U.S. District Court for the Southern District of New York or the U.S. Court of Appeals for the Second Circuit would continue to accept the Utilities’ General and Refunding Mortgage Bonds as sufficient collateral to support a stay of the Judgment pending further appeal.

Management believes that the stay of execution of the Judgment will be continued during the appeal process and that there will be no additional requirement to post cash collateral. As discussed earlier, the June 30, 2004, stipulation provides that the stay of execution of the Judgment, as ordered by the Bankruptcy Court, shall remain in place without any additional principal contributions during the pendency of any and all of the Utilities’ appeals of the Judgment, including to the United States Supreme Court, until a final non-appealable judgment is obtained. However, management does believe that the Utilities would have the means to meet a payment obligation on the Judgment. The Utilities entered into a Remarketing Agreement with Enron and two investment banks as Remarketing Agents to provide for the remarketing of the NPC’s $186 million General and Refunding Mortgage Bond, Series H and SPPC’s $92 million General and Refunding Mortgage Bond which are presently held in escrow. Management believes that the Remarketing Agreement will facilitate the successful remarketing of the Bonds to satisfy the Utilities’ payment obligations with respect to the Judgment. The Remarketing Agreement provides that upon the occurrence of certain events, such as the lifting of the stay of execution of the Judgment or if the Utilities lose their appeal and do not seek a stay of execution of the Judgment pending their further appeal, Enron has the 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 Agents.

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. In the event that the Bonds are not remarketed, there can be no assurance that the Utilities will have available cash or liquidity facilities in place to provide for the payment of the Bonds.

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. Management believes that all amounts ultimately paid to Enron as a result of the above-described litigation are properly recoverable through rates; however, there is no assurance that the PUCN will allow recovery of any amounts ultimately paid to Enron.

Liquidity and Financing Matters

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 the Utilities’ cash flows will be sufficient, to dividend amounts needed in order for SPR to meet its remaining debt service requirements for 2004.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Management believes the establishment of NPC’s and SPPC’s revolving credit facilities will alleviate their short-term liquidity concerns, including any higher than expected prices for fuel and purchased power or significant changes to their current payment terms.

Regulatory

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 actively address any potential concerns, the Utilities continue to work closely with the PUCN in implementing new energy risk management and fuel procurement polices, 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. NPC filed an amendment to the resource plan in June 2004 requesting that the PUCN approve the acquisition and completion of a partially constructed 1,200 MW power plant located within its control area. NPC concurrently filed a long-term financing application to complete the transaction and construction. Hearings will be held in late August 2004. If approved, the acquisition is expected to close in early October 2004 and the plant is expected to be complete by the summer of 2006. In July 2004, SPPC filed its triennial resource plan seeking, among other things, authority to construct a new 500 MW plant by the summer of 2008. The Utilities are also required to seek PUCN approval for power purchases with terms of three years or more, and may seek approval for shorter term contracts. The Utilities’ fuel and purchased power portfolio includes PUCN-authorized long-term purchases from several energy suppliers, both conventional and renewable.

Additionally, pursuant to newly enacted regulations 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. PUCN review and approval of so-called energy supply plans are necessary to ensure regulatory concurrence that appropriate levels of risks are being mitigated at reasonable costs and acceptance that decisions to manage risks are reasonable and made with the best available information at the point in time when decisions are made. 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 was filed along with its resource plan in July 2004.

Management believes they have the ability to implement the planned actions discussed above 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 an adverse outcome related to the uncertainties discussed above.

NOTE 3. SEGMENT INFORMATION

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

Information as to the operations of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which the primary financial measure is business segment operating income. Intersegment revenues are not material.

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


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

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


Three Months Ended	NPC		SPPC			Total							Reconciling
June 30, 2003	Electric		Electric			Electric		Gas		Other			Eliminations		Consolidated
Operating Revenues	$	425,512	$	205,026		$	630,538	$	35,873	$	(160	)	$	—	$	666,251

Operating Income (Loss)	$	10,484	$	(8,832	)	$	1,652	$	782	$	3,759		$	—	$	6,193

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

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

Assets	$	4,533,614	$	2,145,210	$	6,678,824	$	250,777	$	179,746	$	67,770	$	7,177,117


Six Months Ended	NPC		SPPC		Total						Reconciling
June 30, 2003	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	757,164	$	410,480	$	1,167,644	$	100,490	$	629	$	—	$	1,268,763

Operating Income	$	27,897	$	11,399	$	39,296	$	4,371	$	9,349	$	—	$	53,016

NOTE 4. REGULATORY ACTIONS

Nevada Power Company 2003 General Rate Case

NPC filed its biennial General Rate Case on October 1, 2003, as required by law. NPC’s analysis and presentation of the costs of providing electric service (exclusive of purchased fuel and purchased power) indicated that it is necessary to increase the revenue requirement for general rates by $142 million annually.

NPC updated the General Rate Case filing with its Certification filing dated December 14, 2003. The certification filing reduced NPC’s request from $142 million to $133 million. On March 26, 2004, the PUCN issued an order allowing $48 million of the $133 million rate increase requested by NPC. The general rate decision reflects the following significant items:

• A Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.03%, an improvement over NPC’s previous ROE and ROR, which were 10.1% and 8.37%, respectively. NPC had requested an ROE of 12.4% and ROR of 10.0%;

• Approximately $7 million of the $8.8 million of goodwill and merger costs requested to be recovered annually over each of the next two years;

• Approximately $21.4 million of generation divestiture costs to be recovered over an extended period of 8 years;

• Approved the establishment of a regulatory asset account to capture costs related to the shutdown of the Mohave Power Plant.

The PUCN removed from cost of service various items requested by NPC through its general rates filing including costs associated with NPC’s 2003 short-term incentive compensation plan and NPC’s request to earn a rate of return on the cash balances NPC maintained to ensure sufficient liquidity to procure power. In addition, the PUCN’s decision provided for a decrease to NPC’s general rates to allow NPC’s customers to share the benefit of approximately $8.3 million per year for the next two years of gains from recent land sales by NPC.

On April 12, 2004, the Bureau of Consumer Protection (BCP) filed a petition with the PUCN requesting reconsideration and clarification of the Commission’s decision regarding three issues: 1) income taxes and liberalized depreciation, 2) the recovery of merger costs and 3) the proper accounting treatment of rental revenue associated with a property sold by NPC.

On the same date, NPC filed a petition with the PUCN requesting clarification of the order with respect to the Commission’s decision to re-characterize $100 million of equity as debt to determine NPC’s capital structure for rate making purposes and clarification of the regulatory treatment of goodwill and other merger costs.

The PUCN responded to the BCP’s and NPC’s filings on May 20, 2004 and June 7, 2004. The PUCN’s May 20 order denied two of the issues on which the BCP requested reconsideration, and granted clarification on the third issue. The clarification addressing rental revenue resulted in an overall reduction in the revenue requirement of $1.6 million. The PUCN’s order concluded that the petition was granted in part since clarification had been given on the requested issues and denied in part since NPC’s requested revisions to the order were not accepted.

Nevada Power Company 2003 Deferred Energy Case

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

rate to collect accumulated purchased fuel and power costs of $93 million. On March 26, 2004, the PUCN granted approval for NPC to increase its going forward energy rate as filed, approved recovery for $89 million of its deferred balance, denied $4 million, and denied NPC’s request for a tax gross-up on the equity portion of carrying charges. Of the $4 million disallowed only $1.6 million was charged to income in the current period as the remaining amount has previously been expensed. The PUCN ordered the change in going forward rates to take effect April 1, 2004 and delayed the implementation of the deferred energy balance recovery until January 1, 2005 when the 2001 deferred balance is expected to have been completed.

Nevada Power Company Additional Finance Authority

NPC Application for $230 Million Long-Term Debt Authority

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 existing debt securities, as well as to provide additional liquidity to support utility operations. On March 31, 2004, the PUCN approved NPC’s financial application with a restriction on NPC’s ability to dividend funds up to SPR. The restriction does not prohibit NPC from paying dividends to SPR for amounts necessary for SPR to meet its future interest payment requirements. NPC has used the full amount of this long-term authority for the issuance of its $130 million 61/2% General and Refunding Mortgage Notes, Series I, due 2012 and for its $100 million revolving credit facility.

Moapa Energy Facility

NPC filed an amendment to its 2003 Resource Plan on June 29, 2004. The amendment requests PUCN authorization to acquire a partially completed power plant, the “Moapa Energy Facility”, from Duke Energy for $182 million. This amendment requests approval to substitute the 1,200 MW Moapa Energy Facility, which is expected to become operational in early 2006, for the previously approved Harry Allen 520 MW combined cycle generator, which was to come on line in 1997.

NPC has requested that the Moapa Energy Facility be designated as a “critical facility” in accordance with the PUCN’s regulations, which allow for an enhanced return on equity on the designated “critical facility” over the life of the facility. NPC has requested a 5% ROE incentive and specific regulatory asset treatment for this facility.

The Moapa Energy Facility is comprised of two 600 MW combined cycle generators located in the Moapa Valley north of Las Vegas. The filing provides NPC’s due diligence work, the contract and finance plan. The estimated cost to complete construction is $376 million making the total costs $558 million.

PUCN hearings to consider the Resource Plan amendment and an associated financing filing are scheduled for late August 2004. The transaction with Duke Energy is expected to close before October 15, 2004. A future general rate case will be required before NPC can include the costs for this facility in customers’ rates.

Moapa Energy Facility Financing Plan

On June 23, 2004, NPC announced that it reached an agreement to acquire from Duke Energy the partially constructed 1,200 MW (megawatts) natural gas-fired combined-cycle power plant located in the Moapa Valley, “Moapa Energy Facility”. Total costs to acquire and complete construction of the facility are estimated at $558 million, of which $182 million is for the facility in its current state of completion. The transaction, which is subject to approval by the PUCN, is expected to close this fall and NPC expects to finance this purchase and complete construction with a combination of the issuance of secured debt and internally generated cash.

On June 29, 2004, NPC filed an amendment to its 2003 Integrated Resource Plan and an associated $500 million financing application. The financing plan associated with the proposed purchase and construction, and as outlined in the Financing Application, consists of two parts:

1st: NPC expects to finance the acquisition with a $250 million revolving credit facility that will be put in place contingent upon closing the transaction. This revolving credit facility will fund the $182 million acquisition price as well as some of the initial construction expenditures.

2nd: Before the end of the year or early next year, NPC expects to go to market with an offering for long-term financing of approximately $250 million. The proceeds from this financing will be used to pay down the revolver.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

investment in the facility, with the intention to finance the plant approximately 50 percent with equity and 50 percent with long-term debt.

Sierra Pacific Power Company 2003 General Rate Case

SPPC filed its biennial general rate case on December 1, 2003, as required by law. SPPC requested an $87 million increase in the annual revenue requirement for general rates. On April 1, 2004, SPPC, the Staff of the Public Utilities Commission of Nevada and other interveners in SPPC’s 2003 general rate case negotiated a settlement agreement that resolved most of the issues in the revenue requirement and cost of capital portions of SPPC’s case. The agreement, which has since been approved by the PUCN, includes the following provisions:

• SPPC is allowed to recover a $40 million increase in annual rates.

• SPPC is allowed a Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.26%, an improvement over SPPC’s previous ROE and ROR, which were 10.17% and 8.61%, respectively. SPPC had sought an ROE of 12.4% and ROR of 10.03%.

• The agreement accepted SPPC’s requested accounting treatment as filed in its application for purposes of recording revenues, expenses and assets with the following exception. Accounting issues common to SPPC’s general rate case and NPC’s general rate case that was decided by the PUCN on March 26, 2004, in Docket No. 03-10001, are treated as set forth in the PUCN’s Order on NPC’s general rate case, except for merger costs. The accounting treatment for merger costs and goodwill established in the NPC decision will apply to the recovery of these costs by SPPC, except that SPPC will include in rates 100% of the costs as filed until recovery is reset by the PUCN in SPPC’s next general rate application.

The parties also reached a stipulated agreement that resolved the rate design issues in the case.

Investments in the Piñon Pine generating facility were not addressed by the stipulation. SPPC had sought recovery of its investment of approximately $96 million ($90 million associated with the Nevada jurisdiction) for costs associated with this facility over an extended period (between 10 and 25 years). The recovery of these costs would be in addition to the $40 million annual increase provided for by the stipulation agreement.

On May 27, 2004, the PUCN issued an order accepting the two stipulations and responding to SPPC’s request for recovery of the Piñon investments. The PUCN permitted recovery of approximately $37 million (Nevada jurisdictional) of the costs plus a carrying charge to be amortized over 25 years and approximately $11 million (Nevada jurisdictional) of costs without a carrying charge to be amortized over 10 years. The PUCN order granted a $46.7 million increase to SPPC’s general revenues.

As a result of the PUCN order, SPPC evaluated the Piñon Pine generating facility for impairment under the provisions of SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs”. As a result of this evaluation, SPPC recognized an impairment loss of approximately $47 million in the second quarter of 2004. The impairment loss recognized consists of disallowed costs of approximately $43 million and an additional $4 million loss because the PUCN did not permit a carrying charge on $11 million of the costs to be recovered.

SPPC filed a petition for judicial review of the PUCN’s Piñon Decision in the Second Judicial District Court of Nevada on June 8, 2004. The petition is based on existing resource planning statutes and regulations as they apply to the Piñon project. The Piñon project was approved by the PUCN in SPPC’s 1992 Integrated Resource Plan as presented. SPPC does not know the timing of a decision from this court.

Sierra Pacific Power Company 2004 Deferred Energy Case

On January 14, 2004, 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, 2002, and November 30, 2003. The Application requested a deviation from regulation and historic practice and to put in place an asymmetric amortization of the deferred energy balance of approximately $42 million, which would result in recovery of $8 million effective July 2004; $17 million effective July 2005; and $17 million effective July 2006. The Application also requested a deviation from regulation in resetting the BTER (Base Tariff Energy Rate). That methodology and its results would result in no change to the currently effective BTER.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expected repayment of previous deferred balances. The PUCN also ordered SPPC to implement a higher BTER rate (the rate paid for going forward energy purchases) than that requested by the Company. The higher BTER rate represents an overall increase of 4.4 percent in electric rates for SPPC and became effective July 15, 2004.

Sierra Pacific Power Company Additional Finance Authority

SPPC Application for $230 Million Long-Term Debt Authority

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. This matter was designated as Docket Number 03-12030. On April 8, 2004, the PUCN approved SPPC’s financial application with a restriction on SPPC’s ability to dividend funds up to SPR. The restriction does not prohibit SPPC from paying dividends to SPR for amounts necessary for SPR to meet its future interest payment requirements. SPPC has used the full amount of this long-term authority for the issuance of its 61/4% General and Refunding Mortgage Notes, Series H, due 2012 and its $80 million General and Refunding Mortgage Note, Series J, due 2009 (issued in connection with the remarketing of the $80 million Water Facilities Refunding Revenue Bonds discussed in Note 6 of the Condensed Notes to Consolidated Financial Statement, Long-Term Debt) and for its $50 million revolving credit facility.

NOTE 5. SHORT-TERM BORROWINGS

Nevada Power Company

Accounts Receivable Facility

On May 4, 2004, NPC delivered a notice of termination of its accounts receivable facility in connection with the establishment of its new revolving credit facility. The termination was effective on May 19, 2004.

Sierra Pacific Power Company

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 notes were paid off in March 2004.

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 with Lehman Commercial Paper Inc. Borrowings under the Series G Note were to be used to provide back-up liquidity for SPPC during its 2003-2004 winter peak. This credit facility was never used prior to its maturity on March 31, 2004.

Accounts Receivable Facility

On May 4, 2004, SPPC delivered a notice of termination of its accounts receivable facility in connection with the establishment of its new revolving credit facility. The termination was effective on May 19, 2004.

NOTE 6. LONG-TERM DEBT

As of June 30, 2004, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the balance of 2004, for the next four years and thereafter are shown below (dollars in thousands):

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


							SPR Holding
							Co. and Other
	NPC			SPPC			Subs. (1)			SPR Consolidated
2004	$	3,220		$	1,025		$	17,550		$	21,795
2005		6,091			2,400			—			8,491
2006		6,509			52,400			—			58,909
2007		5,949			2,400			240,218			248,567
2008		7,066			322,400			—			329,466

		28,835			380,625			257,768			667,228
Thereafter		2,026,023			617,850			635,000	(2)		3,278,873

		2,054,858			998,475			892,768			3,946,101
Unamortized (Discount Amount)		(10,882	)		(779	)		(6,591	)		(18,252	)

Total	$	2,043,976		$	997,696		$	886,177		$	3,927,849

(1) SPR Holding Co. and Other Subs. includes the debt of Sierra Pacific Communications of $17.6 million which is included in “Liabilities of Discontinued Operations”. See Note 12 in the Condensed Notes to Consolidated Financial Statements, Disposal of Assets.

(2) SPR’s “Thereafter” amount of $635 million includes the total amount of the 7.25% Convertible Notes due at maturity ($300 million). This differs from the carrying value of $237,974 million included in the balance sheet amount of Long-term debt, which is being accreted to face value using the effective interest method.

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

Nevada Power Company

General and Refunding Mortgage Notes, Series I

On April 7, 2004, NPC issued and sold $130 million of its 61/2% General and Refunding Mortgage Notes, Series I, due April 15, 2012 that were issued with registration rights. The proceeds of the issuance were used to pay off $130 million aggregate principal amount of NPC’s 6.20% Series B, Senior Notes due April 15, 2004.

The Series I Notes, similar to NPC’s 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 7 of the Condensed Notes to Consolidated Financial Statements, Dividend Restrictions.

The terms of the Series I Notes, as with 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 permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC’s obligations with respect to energy suppliers, or

3. in the case of the Series I Notes and Series G Notes and the Series H Bond, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan.

If NPC’s Series I Notes, 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 I Notes, 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revolving Credit Facility

On May 4, 2004, NPC established a $100 million Revolving Credit Facility that matures May 4, 2009. Borrowings under this facility will be evidenced on NPC’s General and Refunding Mortgage Bond, Series J, due 2009. The new Revolving Credit Facility replaces the previous Accounts Receivable Credit Facility, which was terminated on May 19, 2004.

NPC may, from time to time, access this facility for loans in increments of $1 million up to the limit of the facility. The rate for outstanding loans will be London Interbank Offered Rate (LIBOR) plus an applicable margin of 2.5%. On June 30, 2004, NPC drew upon this new Revolving Credit Facility for $10 million to meet necessary liquidity needs for ongoing operations. NPC repaid its outstanding borrowings on August 4, 2004.

This Revolving Credit Facility, similar to earlier General and Refunding Mortgage Notes outlined below, contains various covenants and restrictions.

The Revolving Credit Facility limits the amount of payments in respect of common stock dividends that NPC may pay to SPR. This limitation is discussed in Note 7 of the Condensed Notes to Consolidated Financial Statements, Dividend Restrictions.

The Revolving Credit Facility restricts 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 credit agreement, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC’s obligations with respect to energy suppliers, or indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan.

Among other things, the Revolving Credit Facility also contains restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. There are also limitations on certain fundamental structural changes to NPC and limitations on the disposition of property.

Sierra Pacific Power Company

General and Refunding Mortgage Notes, Series H

On April 16, 2004, SPPC issued and sold $100 million of its 61/4% General and Refunding Mortgage Notes, Series H, due April 15, 2012. The Series H Notes were issued with registration rights. The proceeds of the issuance along with operating cash were used to pay off SPPC’s 10.5% Term Loan Facility, due October 2005.

The Series H Notes limit the amount of payments in respect of common stock dividends that SPPC may pay to SPR. This limitation is discussed in Note 7 of the Condensed Notes to Consolidated Financial Statements, Dividend Restrictions.

The terms of the Series H Notes also restrict SPPC from incurring any additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’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 Series H Notes, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, or

3. indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Integrated Resource Plan.

If SPPC’s Series H Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the Series H Notes remain investment grade.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the holders of these securities are entitled to require that SPPC repurchase their securities for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

Water Facilities Refunding Revenue Bonds

On May 3, 2004, SPPC’s $80 million Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest rate on the bonds was adjusted from their prior one year 7.50% term rate to a 5.0% term rate for the period of May 3, 2004 up to and including July 1, 2009. The bonds will be subject to remarketing on July 1, 2009. 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 3, 2004 up to and including July 1, 2009, SPPC’s payment and purchase obligations in respect of the bonds are secured by SPPC’s $80 million General and Refunding Mortgage Note, Series J, due 2009.

Revolving Credit Facility

On May 4, 2004, SPPC established a $50 million Revolving Credit Facility that matures May 4, 2008. Borrowings under this facility will be evidenced on SPPC’s General and Refunding Mortgage Bond, Series K, due 2008. The new Revolving Credit Facility replaces the previous Accounts Receivable Credit Facility, which terminated on May 19, 2004.

SPPC may, from time to time, access this facility for loans in increments of $1 million up to the limit of the facility. The rate for outstanding loans will be LIBOR plus an applicable margin of 2.5%. As of June 30, 2004, SPPC had not drawn on this Revolving Credit Facility.

This Revolving Credit Facility, similar to the Series H Notes outlined above, contain various covenants and restrictions.

The Revolving Credit Facility limits the amount of payments in respect of common stock dividends that SPPC may pay to SPR. This limitation is discussed in Note 7 of the Condensed Notes to Consolidated Financial Statements, Dividend Restrictions.

The Revolving Credit Facility restricts SPPC from incurring any additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’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 Credit Agreement, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, or indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Integrated Resource Plan.

Among other things, the Revolving Credit Facility also contains restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. There are also limitations on certain fundamental structural changes to SPPC and limitations on the disposition of property.

Sierra Pacific Resources

On March 19, 2004, SPR issued and sold $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014 which were issued with registration rights. The proceeds of the issuance were used to fund the repurchase of approximately $174 million in principal amount of SPR’s 83/4% Notes due 2005 at a price equal to approximately 107.225% of the principal amount thereof that were tendered pursuant to SPR’s tender offer.

The balance of the net proceeds were used on May 21, 2004 to legally extinguish the approximately $126 million of remaining principal amount of SPR’s 83/4% Notes due 2005 which were not tendered, and to pay associated interest and fees and expenses associated with the tender offer and the Notes offering. The total cost to extinguish the debt was approximately $23.7 million consisting of tender fees, interest costs and unamortized debt issuance costs.

The terms of the SPR Senior Notes restrict SPR and any of its Restricted Subsidiaries (NPC and SPPC) from incurring any additional indebtedness unless:

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or

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

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

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

Among other things, the SPR Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of SPR or any of its Restricted Subsidiaries, the holders of these securities are entitled to require that SPR repurchase their securities for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

NOTE 7. 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 a 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 SPR), 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, NPC’s General and Refunding Mortgage Bond, Series H, which was issued December 4, 2003, NPC’s 61/2% General and Refunding Mortgage Notes, Series I, due 2012, which were issued on April 7, 2004, and NPC’s Revolving Credit Agreement, which was established on May 4, 2004, limit the amount of payments in respect of common stock that NPC may make 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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The terms of the various series of Notes, the Bond and the Revolving Credit Agreement also permit NPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed:

• under the Series E Notes, $15 million from the date of the issuance of the Series E Notes, and

• under the Series G, Series I Notes and the Series H Bond, and the Revolving Credit Agreement, $25 million from the date of the issuance of the Series G, Series I Notes and the Series H Bond and the establishment of the Revolving Credit Agreement, 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, G, and I Notes or the Series H Bond or the Revolving Credit Agreement,

• 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 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, the Bond or Credit Facility, 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, Series I 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.

• 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 6 1/4 % General and Refunding Mortgage Notes, Series H, due 2012, which were issued on April 16, 2004 and SPPC’s Revolving Credit Agreement, which was established on May 4, 2004, and SPPC’s General and Refunding Mortgage Bond, Series E, which was issued on December 4, 2003, limit the amount of payments in respect of common stock 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 Premium Income Equity Securities (PIES)) provided that:

• those payments do not exceed $50 million for any one calendar year,

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

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

million from the date of the issuance of the Series H Notes, the establishment of the Revolving Credit Agreement and issuance of the Series E Bond, respectively.

In addition, SPPC 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 H Notes, the Revolving Credit Agreement, or the Series E Bond,

• SPPC has a ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2 to 1, and

• the total amount of such dividends is less than:

• the sum of 50% of SPPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series H Notes, the establishment of the Revolving Credit Agreement or the issuance of the Series E Bond, plus

• 100% of SPPC’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 SPPC, plus

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

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

If SPPC’s Series H Notes or the Series E 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 Bond remain investment grade.

• 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 March 31, 2004, the PUCN issued an order in connection with its authorization of the issuance of long-term debt securities by NPC. On April 8, 2004, the PUCN issued an order in connection with its authorization of the issuance of long-term debt securities by SPPC. These PUCN orders, for NPC Docket 04-1014 and SPPC Docket 03-12030, permit NPC and SPPC to annually dividend an aggregate of either SPR’s actual cash requirements for debt service, or $70 million, whichever is less. These orders, in conjunction with earlier orders on this issue, also provide that the dividend limitation may be reviewed in a subsequent application to grant short-term debt authority and that, in the event that circumstances change 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 circumstances, 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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Series H Notes, Series E Bond and its Revolving Credit 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 PUCN dividend restriction of either SPR’s actual cash requirements for debt service, or $70 million, whichever is less, is less than the aggregate amount of the Utilities’ most restrictive individual dividend restrictions.

NOTE 8. DERIVATIVES AND HEDGING ACTIVITIES

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

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

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


	June 30,								December 31,
	2004								2003
	SPR			NPC		SPPC			SPR		NPC		SPPC
Risk management assets	$	26.8		$	12.2	$	14.6		$	22.1	$	11.7	$	10.4
Risk management liabilities	$	6.2		$	4.0	$	2.2		$	16.5	$	5.2	$	11.3
Risk management regulatory assets (liabilities)	$	(6.9	)	$	0.4	$	(7.3	)	$	14.3	$	3.1	$	11.2

Also included in risk management assets were $13.5 million, $8.5 million, and $5.0 million in payments for gas options by SPR, NPC, and SPPC, respectively, at June 30, 2004.

NOTE 9. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

Because of the coal and water supply issues at Mohave, NPC is preparing for the shutdown of the facility by the end of 2005. In July 2003, NPC filed an Integrated Resource Plan (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 to be applied to Mohave in order to recover the remaining net book value of approximately $40.9 million by the 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. On March 26, 2004, the PUCN granted NPC’s proposed alternative recommendation for the creation of a regulatory asset, assuming that the Mohave Plant is closed. However, if NPC is unsuccessful in obtaining recovery of the regulatory asset in a future rate case and the asset is deemed impaired in accordance with SFAS No. 90, Accounting for Abandonments and Disallowances of Plant Costs, there could be an adverse effect on NPC’s and SPR’s financial position, results of operations, and future cash inflows.

In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Total new pond construction and lining costs are estimated at $32.4 million, of which, approximately $18.5 million has already been spent, including approximately $.4 million in 2004. Estimated total capital expenditures in 2004 and 2005 are approximately $1.1 million and $5.7 million, respectively.

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 has been completed, and a dual phase extraction remediation system, which was approved by NDEP, commenced operation in October 2003. The remediation system remains in operation and this effort has shown positive response to cleaning up the oil.

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 this 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, which management believes is sufficient to cover reclamation costs. Currently, management is continuing to evaluate various options including reclamation and sale.

Sierra Pacific Power Company

In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. The steering committee is obtaining cost estimates for removal of the buildings; the cost is not expected to be material. 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, owned 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 system will be installed in August 2004 and remediation should be complete by late fall of 2004. A one-year monitoring period will then be required for verification of clean-up. The cost to implement and monitor this system is not material. This property was sold in the second quarter of 2004. LOS retains the environmental liability until closure.

Litigation Contingencies

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

On June 5, 2002, Enron Power Marketing, Inc. (“Enron”) filed suit against the Utilities in its bankruptcy case in the U.S. Bankruptcy Court for the Southern District of New York asserting claims against the Utilities for liquidated damages in the amount of approximately $216 million and $93 million based on its termination of its power supply agreements with NPC and SPPC, respectively, and for power previously delivered to the Utilities. Enron asserted its contractual right under the Western Systems Power Pool Agreement (WSPPA) to terminate deliveries based upon the Utilities’ decision not to provide adequate assurance of the Utilities’ performance under the WSPPA. The Utilities dispute that they owe the monies sought by Enron and have denied liability on numerous grounds, including deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.

On September 26, 2003, the Bankruptcy Court entered a summary judgment (the “Judgment”) in favor of Enron for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment 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. Based on the pre-judgment rate of 12%, NPC and SPPC recognized additional interest expense of $27.8 million and $12.4 million, respectively, in contract termination liabilities in the third quarter 2003. Also, NPC and SPPC recorded additional contract termination liabilities for liquidated damages of $6.6 million and $2.1 million, respectively, in the third quarter of 2003. The Bankruptcy Court’s order 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 NPC’s $235 million General and Refunding Mortgage Bond, Series H plus SPPC’s $103 million General and Refunding Mortgage Bond, Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which would lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made the payments as ordered on February 10, 2004. The Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall seek a ruling from the PUCN to determine whether the cash payments into escrow trigger the Utilities’, rights to seek recovery of such amounts through the Utilities’ deferred energy rate cases.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 June 30, 2004, interest costs related to the Judgment of $37.6 million and $16.4 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.

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. In its order, the FERC determined, among other things, that it has jurisdiction over disputes involving interpretations of the WSPPA and that an evidentiary hearing would be required to determine whether Enron lawfully exercised its contract rights under the WSPPA to terminate its energy contracts with the Utilities. An initial decision is expected from the FERC by December 31, 2004. Enron has since filed a petition with the Federal District Court in New York seeking to enjoin the Utilities from proceeding with their FERC complaint. Enron contends that the issues in the Utilities complaint already have been considered in the Enron Bankruptcy court. The Federal District Court has set a hearing date of August 13 to hear oral arguments on Enron’s most recent request. The Utilities are unable to predict the outcome of this FERC proceeding and whether the FERC’s decision in the proceeding will affect their appeal of the Judgment or any subsequent appeals of the Judgment.

Reliant Antitrust Litigation

On April 22, 2002, Reliant Energy Services, Inc. (Reliant), filed a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which cases were consolidated in the Superior Court of the State of California. Plaintiffs (original plaintiffs consist of The People of the State of California, City and County of San Francisco, City of Oakland, and County of Santa Clara) seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

alleging that if there was liability, it should be spread among all energy suppliers. The court granted motions to dismiss, and the case is currently on appeal. Both NPC and SPPC believe they should have no liability regarding this matter, but at this time they are unable to predict either the outcome or timing of a decision.

Nevada Power Company

Morgan Stanley Proceedings

On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated arbitration pursuant to 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 dismissed MSCG’s demand for arbitration and agreed that the issues raised by MSCG were not calculation issues subject to arbitration and that NPC’s contract defenses were likewise not arbitrable.

NPC filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada asking the Court to declare that NPC is not liable for any damages as a result of MSCG’s termination of its power supply contracts. On April 17, 2003, MSCG answered the complaint and filed a counterclaim against NPC 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. MSCG filed a motion to intervene in the Section 206 action commenced by NPC against Enron at FERC, and FERC denied MSCG’s motion. On October 23, 2003, NPC filed a motion to stay the District Court proceedings, pending guidance on applicable legal principles from FERC, which guidance may be provided in connection with a complaint NPC filed against Enron with regard to exercise of default and early termination rights. On February 2, 2004, the District Court granted NPC’s motion, and NPC’s complaint for declaratory relief before that court is now stayed until at least August 12, 2004 pending FERC guidance. On July 22, 2004, FERC issued an order stating that it would convene a hearing regarding the NPC complaint against Enron (discussed above). At this time, NPC is unable to predict the outcome or timing 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 WSPPA 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. With respect to Idaho’s claim, Idaho requested mediation of the contracts. NPC alleged 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 the state of Idaho. NPC moved to dismiss the complaint on jurisdictional grounds. NPC filed its own complaint in State court in Clark County, Nevada in September 2003. In October 2003, Idaho filed a motion to stay the Nevada action pending resolution of the Idaho action, and alternatively, to dismiss the Nevada action for failure to state a claim. Idaho’s motion was denied in December 2003. On June 30, 2004, Idaho and NPC entered into a settlement agreement whereby Idaho’s claims have been dismissed with prejudice in return for a $5 million payment by NPC.

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 WSPPA liquidated damages provision 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

District Court for the District of Nevada for damages resulting from breach of these purchase power contracts. On January 12, 2004, EPME filed a motion to dismiss the complaint on grounds of lack of personal jurisdiction and failure to state a claim for relief. On February 27, 2004, NPC filed its response to the motion to dismiss. EPME replied on March 17, 2004. In June 2004, EPME’s motion to dismiss was denied and discovery is ongoing. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Contract Termination Liabilities

At June 30, 2004, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” were approximately $272 million and $105 million of charges, 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 June 30, 2004, were approximately $240 million and $84 million of charges, 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, the Utilities will pursue recovery of the payments through future deferred energy filings. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amounts not permitted would be charged as a current operating expense. A significant disallowance of these costs by the PUCN could have a material adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Sierra Pacific Resources

Touch America and Sierra Touch America LLC

In 2000, Sierra Pacific Communications (“SPC”), a wholly owned subsidiary of SPR, and Touch America, Inc. (“TAI”, 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 (the “System”) between Salt Lake City, Utah, and Sacramento, California. In September 2002, SPC and TAI entered into the Unit Redemption, Release, and Sale Agreement (“URRS”) whereby SPC redeemed its membership interest in STA and acquired fiber optic assets in the System and an indemnity for System liabilities, for a total purchase price of $48.5 million. SPC executed a $35 million promissory note in favor of STA. TAI remained as the sole member of STA. The project sustained significant cost overruns and several complaints and mechanics liens have been filed against several parties, including STA and SPC, by System contractors and subcontractors, including Bayport Pipeline Company and MasTec North America, Inc.

In June 2003, TAI and all its subsidiaries (including STA) filed a petition for Chapter 11 bankruptcy protection. In August 2003, SPC filed a motion with the bankruptcy court for automatic stay relief, specifically to obtain approval of the offset of its construction costs and other System-related costs against the promissory note. SPC has not recognized a liability for amounts claimed by the contractors and subcontractors in their mechanics’ lien claims because management believes that the URRS that was executed in connection with the purchase of the long-haul assets provides that SPC is allowed to reduce its indebtedness to STA under the current circumstances. In an effort to resolve disputes among TAI, STA, SPC, and AT&T regarding the System, these parties have conducted negotiations which have resulted in the SPC Settlement Agreement. On July 15, 2004, TAI filed a motion with the bankruptcy court seeking approval of the SPC Settlement Agreement; the anticipated hearing date for such motion is July 28, 2004. The SPC Settlement Agreement will be a component of the debtor TAI’s Chapter 11 plan of liquidation. TAI’s disclosure statement is scheduled for an approval proceeding on August 13, 2004. While no hearing date has yet been set for Chapter 11 plan confirmation, TAI has also filed a motion to extend the exclusivity period for approval of the plan through the end of November, and such approval may occur before year-end. See Note 12 in the Condensed Notes to Consolidated Financial Statements, Disposal of Assets.

Other Matters

SPR and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which 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 regulated by the PUCN and, in the case of SPPC, they are also subject to the approval of the 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, Summary of Significant Accounting Policies, of Notes to Financial Statements in the 2003 10-K, for further information.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 would be 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, 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 in current period earnings.

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

On March 26, 2004, the PUCN issued its decision on NPC’s general rate case and deferred energy rate case. On May 27, 2004, the PUCN issued its decision on SPPC’s general rate case accepting the two stipulations and responding to SPPC’s request for recovery of the Piñon investments. On July 7, 2004, the PUCN ruled on SPPC’s deferred energy case, and approved the full recovery of SPPC’s fuel and purchased power costs. See Note 4 of the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for details.

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.

Provisions of Assembly Bill 369, passed by the Nevada Legislature in 2001, 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 in March 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 July 7, 2004, are $285 million and $105 million for NPC and SPPC, respectively, including the deferred provision for terminated supply contracts. See Note 1 of the Condensed Notes to Consolidated Financial Statements, Summary of Significant Accounting Policies for details of the deferred energy balances.

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 instructed 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. On March 24, 2004 the PUCN ruled on NPC’s request for recovery of the costs permitting

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approximately $7 million of the $8.8 million of goodwill and merger costs requested to be recovered annually over each of the next two years until recovery is reset in NPC’s next general rate case. As discussed above, SPPC negotiated a settlement agreement with the Staff of the PUCN and other interveners, which was approved by the PUCN on May 27, 2004, that allows SPPC to recover 100% of the costs as filed until recovery is reset by the PUCN in SPPC’s next general rate case. See Note 4 of the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for more information regarding the PUCN orders.

Generation Divestiture Costs

As a condition to the approval in 2001 of the merger between SPR and NPC, the Utilities agreed to divest their generating assets. Costs were incurred in anticipation of completing the divestiture transactions. In the aftermath of the Western Energy Crisis, AB 369 rescinded the requirement to divest these assets and prohibited sales, if any, until no earlier than July 2003. In its March 24, 2004 and May 27, 2004 decisions, the PUCN approved the recovery of generation divestiture costs over a period of eight years by NPC and SPPC, respectively. As result of the decisions, NPC and SPPC began amortization of approximately $22 million and $14 million of divestiture costs in April and June 2004, respectively.

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.

SPPC was not 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 sought recovery of approximately $96 million ($90 million associated with the Nevada jurisdiction) for costs associated with this facility over an extended period (between 10 and 25 years).

On May 27, 2004, the PUCN issued an order that permitted recovery of approximately $37 million (Nevada jurisdictional) of the project costs plus a carrying charge to be amortized over 25 years and approximately $11 million (Nevada jurisdictional) of costs without a carrying charge to be amortized over 10 years.

As a result of the PUCN order, SPPC evaluated the Piñon Pine generating facility for impairment under the provisions of SFAS No. 90. As a result of this evaluation, SPPC recognized an impairment loss of approximately $47 million in the second quarter of 2004. The impairment loss recognized consists of disallowed costs of approximately $43 million and an additional $4 million loss because the PUCN did not permit a carrying charge on $11 million of the costs to be recovered. See Note 4 in the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for additional information regarding SPPC’s General Rate Case decision.

NOTE 10. EARNINGS PER SHARE

The difference, if any, between basic earnings per share (EPS) and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, the non-employee director stock plan and the Corporate PIES. The Stock Option Plan of 1.3 million shares for 2004 and 1.5 million shares for 2003 for both the three months and six months ended June 30, and Corporate PIES of 17.3 million, with a conversion price between $13.85 and $16.62, for the three months and six months ended June 30, 2004 and 2003, have not been included in the calculation of diluted EPS due to the conversion prices being higher than market prices at June 30, 2004 and 2003. Due to net losses for the three months and six months ended June 30, 2004 and 2003, shares of 200,879 and 193,381 for 2004, and 60,999 and 52,304 for 2003, for the three and six months ended June 30, for stock options, executive long-term incentive plan, non-employee stock plan and employee stock purchase plan were anti-dilutive. Accordingly, Diluted EPS for these periods is computed using the weighted average shares outstanding before dilution.

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. However, due to net losses for the three months and six months ended June 30, 2004 and 2003, the effect of the dividend participation rights under the “two-class” method are anti-dilutive, as such they have not been included in basic or diluted earnings per share.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Potentially dilutive common shares were determined using the treasury stock method or the “if-converted” method as discussed below.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Basic EPS
Numerator ($000)
Loss from continuing operations	$	(40,942	)	$	(188,310	)	$	(83,742	)	$	(196,618	)
Loss from discontinued operations	$	(2,967	)	$	(27,965	)	$	(3,642	)	$	(29,902	)
Loss applicable to common stock	$	(44,884	)	$	(217,250	)	$	(89,334	)	$	(228,470	)
Denominator (1)
Weighted average number of shares outstanding		117,279,506			117,144,486			117,259,726			114,337,776

Per-Share amount
Loss from continuing operations	$	(0.35	)	$	(1.61	)	$	(0.71	)	$	(1.72	)
Loss from discontinued operations	$	(0.03	)	$	(0.24	)	$	(0.03	)	$	(0.26	)
Loss applicable to common stock	$	(0.38	)	$	(1.85	)	$	(0.76	)	$	(2.00	)

(1) The denominator does not include 64,749,110 shares for both periods in 2004 and 23,012,188 shares for both periods in 2003 relating to the convertible notes, as they would be anti-dilutive.

NOTE 11. GOODWILL

On March 26, 2004, the PUCN issued a decision on NPC’s general rate case that included the recovery of goodwill and other merger costs allocated to NPC resulting from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that NPC demonstrated merger savings exceeded merger costs, the requisite requirement for recovery of goodwill and merger costs through rates charged to NPC customers. The PUCN decision permits NPC to recover approximately $4 million per year during the next two years, which is based on a forty-year amortization of NPC’s total goodwill reduced by 20%, or approximately $1 million per year, for customer satisfaction survey results that the PUCN determined required improvement. The decision requires NPC to again demonstrate in its next general rate application that merger savings continue during the test period in that case. The PUCN’s order in that case will determine if any further documentation of merger savings is required in the future. Management expects that it will be able to demonstrate continued savings as a result of the merger as well as satisfactory customer survey results. As a result of the PUCN decision, goodwill of approximately $198 million was reclassified as a regulatory asset and then transferred from SPR to the financial statements of NPC as of March 31, 2004.

On May 27, 2004, the PUCN approved a settlement agreement, previously entered into by SPPC, the Staff of the PUCN and other interveners in connection with SPPC’s 2003 general rate case that permits SPPC recovery of goodwill and other merger costs assigned to SPPC’s electric business. SPPC is permitted to recover approximately $2.4 million per year during the next two years, based on a forty-year amortization of goodwill costs. Similar to the decision reached in NPC’s rate case described above, in order to continue to recover goodwill costs SPPC is required to again demonstrate in its next general rate application that merger savings continue during the test period in that case. Management expects that it will be able to demonstrate continued savings resulting from the merger. As a result of the PUCN decision, goodwill of approximately $96 million was reclassified to a regulatory asset and transferred from SPR to the financial statements of SPPC as of June 30, 2004. See Note 4 of the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for more information regarding the NPC and SPPC general rate decisions.

In addition to amounts discussed above SPR’s Consolidated Balance Sheet as of March 31, 2004, included approximately $4 million of goodwill assigned to SPR’s unregulated operations and $31 million of goodwill allocated to its regulated operations that was not considered for recovery in NPC’s or SPPC’s general rate cases described above. The $31 million of goodwill was comprised of approximately $19 million assigned to SPPC’s regulated gas business and $2 million and $10 million for non-Nevada jurisdictional sales allocated to NPC’s and SPPC’s electric businesses, respectively. SPPC expects to demonstrate in its next general rate case for the gas distribution business that savings from the merger allocable to the gas business exceed goodwill and other merger costs and, as a result, to recover goodwill and merger costs through future gas rates. Accordingly, management has not reviewed goodwill assigned to the gas business for impairment. However, the approximate $12 million of goodwill assigned to NPC’s and SPPC’s electric businesses that is not recoverable through future rates and

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approximately $4 million of goodwill assigned to SPR’s unregulated operations were subject to impairment review under the provisions of SFAS No. 142.

SFAS No. 142 provides that an impairment loss is to be recognized if the carrying value of each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was developed for NPC’s and SPPC’s electric business and for SPR’s unregulated businesses (TGPC and LOS) to determine the fair value of each reporting unit as of March 31, 2004. As part of the impairment testing analysis, management revised certain underlying assumptions utilized in previously performed preliminary analyses, that included, revised cash flow forecasts, an increase in the discount rate applied to future cash flows and other assumptions related to the outcomes of NPC’s and SPPC’s general rate cases. As a result of this impairment testing, SPR recorded a goodwill impairment charge related to NPC’s and SPPC’s electric reporting units of approximately $2 million and $10 million as a charge to other operating expenses in SPR’s, NPC’s and SPPC’s Consolidated Statements of Operations for the quarter ended March 31, 2004. Goodwill assigned to TGPC and LOS was determined not to be impaired.

The change in the carrying amount of goodwill for the six-month period ended June 30, 2004 and the allocation of the remaining balance is as follows (dollars in thousands):


	Regulated			Unregulated
	Operations			Operations		Total
Goodwill balance as of January 1, 2004	$	305,982		$	3,989	$	309,971
Goodwill included in regulatory assets as of January 1, 2004		19,070			—		19,070

Subtotal		325,052			3,989		329,041
Transfer to NPC regulatory asset as of March 31, 2004		(197,998	)		—		(197,998	)
Impairment loss recognized as of March 31, 2004		(11,696	)		—		(11,696	)
Transfer to SPPC regulatory asset as of June 30, 2004		(96,470	)		—		(96,470	)

Balance as of June 30, 2004	$	18,888		$	3,989	$	22,877

Goodwill Allocation to Reporting Units:
SPPC GAS	$	18,888		$	—	$	18,888
TGPC		—			3,520		3,520
LOS		—			469		469

Balance as of June 30, 2004	$	18,888		$	3,989	$	22,877

NOTE 12. DISPOSAL 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. SPC recognized a gain on the sale of assets of approximately $2.5 million (pretax) in connection with the sale of the MAN assets.

Management has also concluded to dispose of SPC’s Long Haul Assets and is currently pursuing that as part of a settlement with Touch America and Sierra Touch America in their bankruptcy proceeding. 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 ($17.5 million as of June 30, 2004) shall be deemed paid and satisfied. The settlement also includes resolution of the lawsuit and other claims discussed in Note 9, Commitments and Contingencies, Litigation Contingencies, Touch America and Sierra Touch America LLC. The settlement also gives SPC title of one remaining duct, that SPC had previously 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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assets. 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 are segregated on the consolidated balance sheets at December 31, 2003 and June 30, 2004. Revenues from SPC for the six months ended June 30, 2004 and 2003 were $811,000 and $673,000, respectively, and pre-tax loss of approximately $3.2 million and $35.5 million. The carrying amount of major asset and liability classifications are as follows (dollars in thousands):


	June 30,		December 31,
	2004		2003
Investments and other property, net	$	29,810	$	36,512
Cash		6,116		32
Current assets — Other		626		3,528

	$	36,552	$	40,072

Current maturities of long-term debt	$	17,550	$	19,666
Current liabilities		19,372		10,995
Deferred credits — Other		37		5,205

	$	36,959	$	35,866

NOTE 13. PENSION AND OTHER POSTRETIREMENT BENEFITS

A summary of the components of net periodic pension and other postretirement costs for the three months and six months ended June 30, 2004 and June 30, 2003 follows. This summary is based on a September 30 measurement date (dollars in thousands):


	Three Months Ended June 30,												Six Months Ended June 30,
	2004			2003			2004			2003			2004			2003			2004			2003
							Other Postretirement												Other Postretirement
	Pension Benefits						Benefits						Pension Benefits						Benefits
Service cost	$	4,497		$	3,802		$	779		$	614		$	8,994		$	7,603		$	1,559		$	1,228
Interest cost		7,568			7,350			2,382			2,221			15,137			14,700			4,764			4,442
Expected return on plan assets		(7,658	)		(5,284	)		(1,034	)		(965	)		(15,316	)		(10,568	)		(2,067	)		(1,930	)
Amortization of prior service cost		428			492			16			16			857			983			32			32
Amortization of Transition Obligation		—			—			242			242			—			—			485			485
Amortization of net (gain)/loss		2,243			2,522			1,157			717			4,486			5,043			2,313			1,433

Net periodic benefit cost	$	7,078		$	8,882		$	3,542		$	2,845		$	14,158		$	17,761		$	7,086		$	5,690

At the present time there is no change expected to the 2004 estimated employer contribution amounts disclosed in Note 13, Retirement Plan and Post-retirement Benefits, of the combined SPR, NPC, and SPPC Annual Report 10-K, as of December 31, 2003. The amounts previously disclosed in that report were $35.5 million for pension and $0.2 million for other postretirement benefits.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters, which may occur or be realized in the future. Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of Sierra Pacific Resources (“SPR”), Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“SPPC”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

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

(2) unfavorable rulings in rate cases filed and to be filed by NPC and SPPC (collectively, the “Utilities”) with the Public Utilities Commission of Nevada (the “PUCN”), including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas recorded by SPPC for its gas distribution business;

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

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

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

(6) whether NPC will receive PUCN approval to purchase a partially constructed 1,200 MW combined-cycle power plant from Duke Energy and to finance the purchase and construction of the power plant;

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

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

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

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

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

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

(13) whether the Utilities will be successful in obtaining PUCN approval to recover the outstanding balance of their goodwill and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

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

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

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

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

(18) the loss of any significant customers;

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

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

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

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

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

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

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

Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. SPR, NPC, and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations for Sierra Pacific Resources (SPR) and its two primary subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC), collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to SPR and the Utilities collectively), and includes the following:

• For each of SPR, NPC and SPPC:

• Results of Operations

• Analysis of Cash Flows

• Liquidity and Capital Resources

• Regulatory Proceedings (Utilities)

• Recent Pronouncements

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

Significant Uncertainties

SPR and its Utilities have faced a variety of uncertainties and risks over the past several years as an aftermath of the so-called Western Energy Crisis. The Utilities exposure to volatile energy markets were and are exacerbated due to insufficient owned generation relative to the growing demand for electricity in Nevada. In March 2002, the Utilities were downgraded by the rating agencies, Moody’s and Standard & Poor’s, after significant write-offs as a result of regulatory disallowances relating to fuel and power purchased during the Western Energy Crisis at a time when, as is now known, Enron and others were manipulating the markets. The Utilities lost access to traditional credit facilities and, as a result, were required to work diligently with suppliers and others to assure that they continued to deliver power to customers. Financings became more expensive and the terms and conditions became more onerous. The write-offs and subsequent Public Utilities Commission of Nevada (PUCN) decisions prevented dividends from NPC to SPR that put in jeopardy SPR’s ability to service its debt. In August 2003 a judgment in excess of $300 million against the Utilities was entered in U.S. bankruptcy court in favor of Enron for contracts that EPMI terminated after the downgrades.

Management’s Discussion and Analysis of Financial Condition and Results of Operation in SPR’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2003 (the “2003 10-K”) discussed in detail significant uncertainties that SPR and the Utilities were and to some extent continue to be challenged by. These uncertainties included:

Since the date of the filing of our 2003 10-K, SPR and the Utilities have made significant progress towards resolving a number of the uncertainties described above. The Utilities have responded aggressively and with positive result to each of the issues. They have instituted new power and fuel procurement, and risk control policies and practices. These changes have been

recognized in recent PUCN decisions, in which the Utilities have recovered virtually all of their fuel and power costs. The Utilities announced a strategy to begin reducing their exposure to volatile swings in power prices through the acquisition of partially constructed power plants that will be complete and put in service by the summer of 2005. SPR and the Utilities have refinanced near-term debt maturities at favorable rates and terms, and have secured liquidity facilities that will be available for several years. Through consent of bondholders and a modification of PUCN restrictions, SPR once again has the ability to service SPR debt though dividends from NPC. The Utilities have appealed the Enron bankruptcy court’s decision in U.S. District court and have also been granted a hearing by the Federal Energy Regulatory Commission in response to their petition claiming that Enron wrongfully terminated the contracts and therefore should not be paid.

So, while SPR and the Utilities continue to face risks and uncertainties they have made efforts to mitigate these uncertainties. The following discussion describes the status of uncertainties described above as of August 6, 2004, and outlines the actions taken by management and recent events that have improved the outlook with respect to these uncertainties.

Enron Litigation

See Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies for further information regarding the Enron litigation.

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. The Utilities are unable to predict whether the FERC’s decision in the proceeding will affect their appeal of the Judgment or any subsequent appeals of the Judgment.

PUCN could have a material adverse effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Financing, Liquidity and Other Matters

• In March 2004, SPR successfully repurchased approximately $174 million of its 8.3/4% Notes due 2005 through the issuance and sale of $335 million 8.625% Senior Notes due 2014. The balance of the net proceeds from the $335 million issuance were used in May of 2004 to legally extinguish the approximately $126 million of remaining principal amount of SPR’s 83/4% Notes which were not tendered, and to pay associated interest and to the payment of fees and expenses associated with the tender offer.

• In April 2004, NPC refinanced $130 million of its 6.2% long-term debt that matured in April 2004 through the issuance and sale of its $100 million 6.5% Series I General and Refunding Mortgage Notes that will mature in April 2012.

• In April 2004, SPPC refinanced $99 million of its 10.5% term loan that was to mature in October 2005 through the issuance and sale of its 6.25% Series H General and Refunding Mortgage Notes that will mature in April 2012.

• In May 2004, SPPC remarketed $80 million of Water Facilities Refunding Revenue Bonds that were subject to mandatory repurchase on May 3, 2004 and adjusted the rate on the bonds from their prior one-year rate of 7.50% to a 5.0% rate in effect through July 1, 2009.

• To support the Utilities power and natural gas purchase requirements at the onset of the summer 2004 season and for other general corporate and working capital purposes, NPC and SPPC replaced their receivables purchase facility with revolving credit facilities. The revolving credit facilities offer the Utilities additional liquidity at more favorable rates than their receivables purchase facilities.

The above financings significantly alleviate the Utilities’ short term financing concerns. However, 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 revolving credit facilities.

Regulatory

NPC’s General Rate Case

NPC’s Deferred Energy Case

On November 14, 2003, NPC filed an application with the PUCN seeking repayment for fuel and purchased power costs accumulated between October 1, 2002 and September 30, 2003. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $93 million. On March 26, 2004, the PUCN granted approval for NPC to increase its going forward energy rate as filed, approved recovery for $89 million of its deferred balance, denied $4 million, and denied NPC’s request for a tax gross-up on the equity portion of carrying charges. Of the $4 million disallowed only $1.6 million was charged to income in the current period as the remaining amount had no impact on earnings or was charged to income in prior periods. The PUCN ordered the change in going forward rates to take effect April 1, 2004 and delayed implementation of the deferred energy balance recovery until January 1, 2005, the time recovery of the 2001 deferred balance is expected to have been completed.

SPPC’s General Rate Case

The parties also reached a stipulated agreement that resolved the rate design issues in the case.

without a carrying charge to be amortized over 10 years. The PUCN order granted a $46.7 million increase to SPPC’s general revenues.

As a result of the PUCN order, SPPC evaluated the Piñon Pine generating facility for impairment under the provisions of SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs.” As a result of this evaluation, SPPC recognized an impairment loss of approximately $47 million in the second quarter of 2004. The impairment loss recognized consists of disallowed costs of approximately $43 million and an additional $4 million loss because the PUCN did not permit a carrying charge on $11 million of the costs to be recovered.

SPPC’s Deferred Energy Case

On January 14, 2004, 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, 2002, and November 30, 2003. The Application requested a deviation from regulation and historic practice and to put in place an asymmetric amortization of the deferred energy balance of approximately $42 million, that would result in recovery of $8 million effective July 2004; $17 million effective July 2005; and $17 million effective July 2006. The Application also requested a deviation from regulation in resetting the BTER (Base Tariff Energy Rate). That methodology and its results would result in no change to the currently effective BTER.

On July 7, 2004, the PUCN ruled on the deferred energy case, and approved a full recovery of the fuel and purchased power costs. The PUCN order delayed the start of the deferred balance recovery until April 2005, which corresponds with the expected repayment of previous deferred balances. The PUCN also ordered SPPC to implement a higher BTER rate (the rate paid for going forward energy purchases) than that requested by the Company. The higher BTER rate represents an overall increase of 4.4% in electric rates for SPPC and became effective July 15, 2004.

Management cannot predict the outcome of future General Rate Cases or Deferred Energy proceedings. Material disallowances, as a result of adverse decisions in future general or deferred rate proceedings would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause additional downgrades of their securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties.

See Regulatory Proceedings, later in Management’s Discussion and Analysis for additional information regarding regulatory proceedings.

Business Strategies

Enron Litigation

States Supreme Court, until a final non-appealable judgment is obtained. However, management does believe that the Utilities would have the means to meet a payment obligation on the Judgment. The Utilities entered into a Remarketing Agreement with Enron and two investment banks as Remarketing Agents to provide for the remarketing of NPC’s $186 million General and Refunding Mortgage Bond, Series H and SPPC’s $92 million General and Refunding Mortgage Bond which are presently held in escrow. Management believes that the Remarketing Agreement will facilitate the successful remarketing of the Bonds to satisfy the Utilities’ payment obligations with respect to the Judgment. The Remarketing Agreement provides that upon the occurrence of certain events, such as the lifting of the stay of execution of the Judgment or if the Utilities lose their appeal and do not seek a stay of execution of the Judgment pending their further appeal, Enron has the 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 Agents.

Liquidity and Financing Matters

Regulatory

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. NPC filed an amendment to the resource plan in June 2004 requesting that the PUCN approve the acquisition and completion of a partially constructed 1,200 MW power plant. NPC concurrently filed a long-term financing application to complete the transaction and construction. Hearings will be held in late August 2004. If approved, the acquisition is expected to close in early October 2004 and the plant is expected to be complete by the summer of 2006. In July 2004, SPPC filed its plan including, among other things, a new 500 MW plant to be built by the summer of 2008. The Utilities are required to seek PUCN approval for power purchases with terms of three years or more, and also may seek approval for shorter term contracts.

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 was filed along with its resource plan in July 2004.

Management’s planned strategies are designed to mitigate these risks and uncertainties. However, if the uncertainties discussed above are resolved adversely to the Utilities, SPR would likely experience one-time charges that would offset in whole or in part SPR’s earnings and gains and could result in significant losses to SPR. Adverse developments with respect to these uncertainties could have a material adverse effect on SPR’s, NPC’s and SPPC’s financial condition and liquidity.

SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Holding Company)

The Holding Company’s (stand alone) operating results included approximately $49.6 million and $38.0 million of long term debt interest costs for the six months ended June 30, 2004 and 2003, respectively. Long-term debt interest expense increased primarily as a result of interest paid on the early termination of debt. Interest charges — other of approximately $16.5 million and $2.0 million for the six months ended June 30, 2004 and 2003, respectively, increased as a result of the tender fees associated with the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes due 2005. (See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt). The Holding Company’s consolidated operating results for the six months ended June 30, 2004, compared favorably to the same period in 2003, primarily due to an unrealized loss recorded in June 2003 of approximately $123.5 million on the derivative associated with the issuance of $300 million of convertible debt. The improved 2004 operating results were partially offset by the following items recorded in 2004: an impairment of goodwill of approximately $11.7 million; the non-cash write-off of disallowed merger costs of approximately $5.9 million; and approximately $21.5 million of tender fees and interest costs associated with the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes due 2005. (See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt for discussion on the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes).

Sierra Pacific Resources (Consolidated)

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

During the three months ended June 30, 2004, SPR incurred a loss applicable to common stock of approximately $44.9 million compared to an approximate $217 million loss applicable to common stock for the same period in 2003. The decrease in SPR’s consolidated loss during 2004 compared to 2003 was primarily due to (before income taxes):

• an unrealized loss of approximately $123.5 million on the derivative instrument associated with the issuance of $300 million of convertible debt recorded in the second quarter of 2003;

• the write-off of disallowed deferred energy costs (excluding carrying charges) of approximately $46 million and $45 million by NPC and SPPC, respectively, recorded in the second quarter of 2003; and

• losses by SPR subsidiaries due to the recognition of asset impairments of $32.9 million for SPC recorded in the second quarter of 2003, now reported in Discontinued Operations.

Partially offsetting the improved operating results during 2004 were the following charges:

• a charge of approximately $9.8 million during the second quarter of 2004 of interest expense costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes due 2005. (See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt); and

• a charge of approximately $47 million recorded during the second quarter of 2004 as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Piñon Pine. (See Regulatory Proceedings (Utilities)).

During the six months ended June 30, 2004, SPR incurred a loss applicable to common stock of approximately $89 million compared to an approximate $228 million loss applicable to common stock for the same period in 2003. The decrease in SPR’s consolidated loss during 2004 compared to 2003 was primarily due to the following charges (before income taxes):

• an unrealized loss of approximately $107.6 million on the derivative instrument associated with the issuance of $300 million of convertible debt recorded in 2003;

• the write-off of disallowed deferred energy costs (excluding carrying charges) of approximately $46 million and $45 million by NPC and SPPC, respectively, recorded in 2003; and

• losses by SPR subsidiaries due to the recognition of asset impairments of $32.9 million for SPC recorded in 2003.

Partially offsetting the improved operating results during 2004 were the following charges:

• a non-cash goodwill impairment charge of approximately $11.7 million during 2004 (See Note 11 of the Condensed Notes to Consolidated Financial Statements, Goodwill);

• a non-cash charge in 2004 to write-off disallowed merger costs of approximately $5.9 million;

• a charge of approximately $23.7 million during 2004 of tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes due 2005. (See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt); and

• a charge of approximately $47 million as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Piñon Pine. (See Regulatory Proceedings (Utilities)).

Neither SPR nor SPPC paid or declared a common dividend in the six months ended June 30, 2004. For the six months ended June 30, 2004, NPC paid a common stock dividend of $20.1 million to its parent, SPR. For the six months ended June 30, 2004, SPPC declared and paid $1.95 million in dividends to holders of its preferred stock. In August 2004, NPC declared a common stock dividend of $19.9 million to its parent SPR. And SPPC declared a dividend of $975,000 to holders of its preferred stock.

Management has identified a number of risks and uncertainties that may have a negative impact on SPR’s financial condition and results of operations. These risks and uncertainties are discussed in SPR’s Liquidity and Capital Resources discussion below. If certain of these risks and uncertainties are decided adversely to SPR and the Utilities, SPR would likely experience one-time charges that would offset in whole or in part SPR’s earnings and gains and could result in significant losses to SPR.

ANALYSIS OF CASH FLOWS

SPR’s consolidated net cash flows decreased for the six months ended June 30, 2004 compared to the same period in 2003, as a result of a decrease in cash from operating activities and financing activities partially offset by less cash used in investing activities. Cash flows from operating activities decreased primarily as a result of cash payments of $60 million to the Enron escrow account as required by the Enron Judgment and fuel and purchased power costs exceeding our collection of those costs in rates, both during 2004, and increased collection efforts. Increased collection efforts, initiated in 2003, decreased NPC’s and SPPC’s accounts receivable balance as of December 2003 compared to December 2002. Partially offsetting these decreases were NPC’s and SPPC’s requirement to prepay energy costs in 2003 due to NPC’s and SPPC’s credit ratings.

Cash flows from financing activities was less for the six months ended June 30, 2004 compared to the same period in 2003, primarily as a result of issuance of the Convertible Notes in the first quarter of 2003 and the requirement to deposit approximately $53 million into an escrow account to be pledged for the first five interest payments on the notes payable during the first two and one-half years. The deposit is shown as restricted cash and investments on the balance sheet of SPR. Cash used in investing decreased primarily as a result of a decrease in construction activity in 2004.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

SPR, on a stand-alone basis, had cash and cash equivalents of approximately $20 million at June 30, 2004, which does not include restricted cash and investments of approximately $32 million. The $32 million represents collateral for payment of interest up to and including August 14, 2005 in connection with SPR’s 7.25% Convertible Notes due 2010. SPR paid approximately $42 million of debt service obligations on its existing debt securities as of June 30, 2004. SPR has approximately $36 million payable of debt service obligations remaining during 2004. Approximately $11 million of SPR’s remaining debt service obligations in 2004 will be satisfied with cash included in SPR’s Restricted Cash balance as discussed above. Currently, SPR expects to meet its remaining debt service obligations for 2004 of approximately $25 million 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 7 of the Condensed Notes to Consolidated Financial Statements, Dividend Restrictions for a discussion of the dividend restrictions applicable to the Utilities.

Dividends from Subsidiaries

Dividend Restrictions Applicable to Nevada Power Company

1. 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:

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.

2. 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, NPC’s General and Refunding Mortgage Bond, Series H, which was issued December 4, 2003, NPC’s 6 1/2% General and Refunding Mortgage Notes, Series I, due 2012, which were issued on April 7, 2004, and NPC’s Revolving Credit Agreement, which was established on May 4, 2004, limit the amount of payments in respect of common stock that NPC may make 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.

• under the Series E Notes, $15 million from the date of the issuance of the Series E Notes, and

• under the Series G, Series I Notes and the Series H Bond, and the Revolving Credit Agreement, $25 million from the date of the issuance of the Series G, Series I Notes and the Series H Bond and the establishment of the Revolving Credit Agreement, 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, G, and I Notes or the Series H Bond or the Revolving Credit Agreement,

• 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 to 1, and

• the total amount of such dividends is less than:

• 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.

Dividend Restrictions Applicable to Sierra Pacific Power Company

• those payments do not exceed $50 million for any one calendar year,

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

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

The terms of the Series H Notes, the Revolving Credit Agreement and the Series E Bond also permit SPPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed $25 million from the date of the issuance of the Series H Notes, the establishment of the Revolving Credit Agreement and issuance of the Series E Bond, respectively.

In addition, SPPC 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 H Notes, the Revolving Credit Agreement, or the Series E Bond,

• SPPC has a ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2 to 1, and

• the total amount of such dividends is less than:

• 100% of SPPC’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 SPPC, plus

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

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

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

• The Utilities are subject to the provision of the Federal Power Act, as applied to their particular circumstances, 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.

Accounts Receivable Facility

On October 29, 2002, NPC and SPPC established accounts receivable purchase facilities of up to $125 million and $75 million, respectively. On May 4, 2004, NPC and SPPC delivered a notice of termination of their accounts receivable facilities in connection with the establishment of their revolving credit facilities. The terminations were effective on May 19, 2004.

Financing Transactions (SPR — Holding Company)

On March 19, 2004, SPR issued and sold $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014 which were issued with registration rights. The proceeds of the issuance were used to fund the repurchase of approximately $174 million in principal amount of SPR’s 8 3/4% Notes due 2005 at a price equal to approximately 107.225% of the principal amount thereof that were tendered pursuant to SPR’s tender offer.

The balance of the net proceeds was used on May 21, 2004 to legally extinguish the approximately $126 million of remaining principal amount of SPR’s 8 3/4% Notes due 2005 which were not tendered, and to pay associated interest, fees and expenses associated with the tender offer and the Notes offering. The total cost to extinguish the debt was approximately $23.7 million consisting of tender fees, interest costs and unamortized debt issuance costs.

The terms of the SPR Senior Notes restrict SPR and any of its Restricted Subsidiaries (including NPC and SPPC) from incurring any additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or

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

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

Cross Default Provisions

Certain financing agreements of SPR and the Utilities contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPR and the Utilities to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time SPR or the Utilities may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPR’s and the Utilities’ various financing agreements are briefly summarized below:

• The indentures pursuant to which SPR issued its 7.25% Convertible Notes due 2010 and its 8 5/8% Senior Notes due 2014 provide for an event of default if SPR or any of its significant subsidiaries (NPC and SPPC) fail to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable for so long as the 7.25% Convertible Notes are outstanding;

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

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

Judgment Related Defaults

Nevada Power Company

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

The terms of NPC’s $250 million Series E, $350 million Series G and $130 million Series I General and Refunding Mortgage Notes, $186 million Series H General and Refunding Mortgage Bond and Revolving Credit Agreement, provide for an event of default if a final, unstayed judgment in excess of $15 million is rendered against NPC and remains undischarged for 60 days. Since the Series E, Series G Series I Notes and Series H Bond were issued under NPC’s General and Refunding Mortgage Indenture and NPC’s Revolving Credit Agreement is supported by a General and Refunding Mortgage Bond, a default under any of the Series E, Series G and Series I Notes, Series H Bond and Revolving Credit Agreement, will trigger a default under NPC’s General and Refunding Mortgage Indenture.

In addition, a matured event of default under NPC’s First Mortgage Indenture will trigger a default under NPC’s General and Refunding Mortgage Indenture. Upon a matured event of default under the NPC’s General and Refunding Mortgage Indenture, the trustee or the holders of 33% of the General and Refunding Mortgage securities outstanding may declare the principal and accrued interest of the approximately $1.4 billion of outstanding General and Refunding Mortgage securities as of June 30, 2004, immediately due and payable.

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

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

Sierra Pacific Power Company

SPPC’s Series E Bond, Series H Notes and Revolving Credit Agreement provide for an event of default if a judgment of $15 million or more is entered against SPPC and such judgment is not paid, discharged, or stayed for a period of 60 days. The Notes, the Bond and Revolving Credit Agreement also prohibit the creation or existence of any liens on SPPC’s properties except for liens specifically permitted under the terms of Notes, the Bond or Revolving Credit Agreement.

Since the Series E Bond, Series H Notes and Revolving Credit Agreement were issued under SPPC’s General and Refunding Mortgage Indenture and SPPC’s Revolving Credit Agreement is supported by a General and Refunding Mortgage Bond, a default under these Notes, the Bond or the Revolving Credit Agreement will trigger a default under SPPC’s General and Refunding Mortgage Indenture. In the event that a triggering event occurs that effectively accelerates the outstanding amounts due under the securities issued under the General and Refunding Mortgage Indenture, SPPC would likely be unable to continue to operate outside of bankruptcy.

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

Effect of Holding Company Structure

Currently, SPR (on a stand-alone basis) has a substantial amount of outstanding debt and other obligations including, but not limited to: $240 million of its unsecured 7.93% Senior Notes due 2007; $300 million of its 7 1/4% Convertible Notes due 2010; and $335 million of its unsecured 8 5/8% Senior Notes due 2014.

Due to the holding company structure, SPR’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors and preferred stockholders. Therefore, SPR’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders, NPC’s preferred trust security holders, and SPPC’s preferred stockholders.

As of June 30, 2004, SPR, NPC, SPPC, and their subsidiaries had approximately $3.9 billion of debt and other obligations outstanding. Additionally, SPPC had $50.0 million of outstanding preferred stock. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Contractual Obligations

During the six months ended June 30, 2004, there were no material changes, outside the ordinary course of SPR’s business, to contractual obligations as set forth in SPR’s 2003 10-K, other than the issuance of the $335 million 8 5/8% Senior Unsecured Notes due March 2014 and the repurchase of approximately $174 million in principal amount and the extinguishment of approximately $126 million in principal amount of SPR’s 8 3/4% Notes due 2005.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2004, NPC recognized net income of approximately $13.6 million compared to a net loss of approximately $22.1 million for the same period in 2003. During the six months ended June 30, 2004, NPC incurred a net loss of approximately $1.8 million compared to a net loss of approximately $37.4 million for the same period in 2003. NPC paid a common stock dividend of $5.7 million to its parent, SPR, in the quarter ended March 31, 2004 and $14.4 million in the quarter ended June 30, 2004. In August 2004, NPC declared a common stock dividend of $19.9 million to its parent, SPR.

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


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Operating Revenues:
Electric	$	449,925	$	425,512		5.7	%	$	776,458	$	757,164		2.6	%
Energy Costs:
Purchased power		191,508		205,129		-6.6	%		319,039		324,386		-1.7	%
Fuel for power generation		60,312		67,910		-11.2	%		109,667		114,447		-4.2	%
Deferral of energy costs-disallowed		—		45,964		N/A			1,586		45,964		-96.6	%
Deferral of energy costs-electric-net		38,808		11,442		N/A			82,126		84,227		-2.5	%

		290,628		330,445		-12.1	%		512,418		569,024		-10.0	%

Gross Margin
Electric	$	159,297	$	95,067		67.6	%	$	264,040	$	188,140		40.3	%

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.

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

Electric Operating Revenues


	Three Months							Six Months
	Ended June 30,				Change from			Ended June 30,				Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Electric Operating Revenues
Residential	$	190,643	$	167,222		14.0	%	$	319,131	$	288,929		10.5	%
Commercial		97,811		86,306		13.3	%		173,066		161,222		7.3	%
Industrial		135,929		128,188		6.0	%		230,327		220,576		4.4	%

Retail		424,383		381,716		11.2	%		722,524		670,727		7.7	%
Other		25,542		43,796		-41.7	%		53,934		86,437		-37.6	%

Total Revenues	$	449,925	$	425,512		5.7	%	$	776,458	$	757,164		2.5	%

Retail sales in thousands of megawatt-hours (MWh)		4,727		4,488		5.3	%		8,488		7,888		7.6	%
Average retail revenue per MWh	$	89.78	$	85.05		5.6	%	$	85.12	$	85.03		0.1	%

NPC’s Retail revenues were higher for the three and six months ended June 30, 2004, when compared to the prior year, due to increases in customer growth, warmer weather, and higher rates. For the six months ended June 30, 2004, the number of residential, commercial, and industrial customers increased by 5.1%, 5.3%, and 6.1%, respectively. Higher electric rates resulted from NPC’s 2003 General and Deferred Energy Rate Cases effective April 1, 2004. These rate increases were partially offset by a decrease in retail rates effective May 19, 2003, which was the result of NPC’s 2002 Deferred Energy Rate Case.

Based on NPC’s projected customer forecast, NPC expects retail electric customers in the Clark County area to continue to grow. Based on this estimated growth in the number of retail customers, NPC expects electric megawatt hours and revenues to increase in the third quarter compared to the second quarter. Also, higher retail rates that were effective April 1, 2004 are expected to increase revenues for the remainder of the year.

The decrease in Electric Operating Revenues — Other for the three and six months ended June 30, 2004, compared to the same periods in 2003, was primarily due to a decrease in the sales volumes for wholesale electric power to other utilities and a reduction in sales associated with risk management activities. See the 2003 10-K, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Energy Supply for a discussion of NPC’s purchased power procurement strategies.

Purchased Power


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Purchased Power	$	191,508	$	205,129		-6.6	%	$	319,039	$	324,386		-1.6	%
Purchased Power in thousands of MWhs		3,137		3,259		-3.7	%		5,498		5,530		-0.6	%
Average cost per MWh of Purchased Power	$	61.05	$	62.94		-3.0	%	$	58.03	$	58.66		-1.1	%

NPC’s purchased power costs were lower for both the three months and six months ended June 30, 2004 compared to the same periods in 2003 primarily due to lower volumes purchased. The decrease in volume is primarily attributable to the increase in megawatts generated and the decrease in wholesale electric sales as discussed in Electric Operating Revenues — Other.

Average cost per MWh of purchased power decreased from the three months and six months ended June 30, 2004 due to NPC entering into two gas tolling agreements during the second quarter of 2004. These gas tolling agreements are purchased power agreements where NPC provides natural gas to the supplier who generates the energy for NPC. In return for generating the energy, NPC pays the supplier a capacity payment for the use of the generating unit and a variable operating and maintenance charge for each megawatt-hour generated. These gas tolling agreements reduce the costs of purchased power because the generating facilities used to generate that energy have more efficient heat rates than those of the other suppliers. The more efficient the heat rate, the less gas required to generate each megawatt-hour of energy.

Fuel For Power Generation


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Fuel for Power Generation	$	60,312	$	67,910		-11.2	%	$	109,667	$	114,447		-4.2	%
Thousands of MWhs generated		2,144		2,044		4.9	%		3,932		3,919		0.3	%
Average cost per MWh of Generated Power	$	28.13	$	33.22		-15.3	%	$	27.89	$	29.20		-4.5	%

Fuel for generation costs for the three and six months ended June 30, 2004 decreased from the same periods in the prior year. The decrease in average cost per MWh was mainly due to higher gas prices in 2003 compared to 2004.

Deferred Energy Costs


	Three Months						Six Months
	Ended June 30,						Ended June 30,
					Change from						Change from
	2004		2003		Prior Year %		2004		2003		Prior Year %
Deferred energy costs disallowed	$	—	$	45,964		N/A	$	1,586	$	45,964		N/A
Deferred energy costs — net	$	38,808	$	11,442		N/A	$	82,126	$	84,227		-2.5	%

Deferred energy costs disallowed for the six months ended June 30, 2004, reflects the write-off of $1.6 million of deferred energy costs incurred during the twelve months ended September 30, 2003, that were disallowed by the PUCN in NPC’s 2003 deferred energy rate case in March 2004. See Regulatory, NPC’s 2003 Deferred Energy Rate Case. Deferred energy costs disallowed for the three and six months ended June 30, 2003, reflects the PUCN disallowance of approximately $46 million in May 2003, of deferred energy costs incurred during the twelve months ended November 2002.

Deferred energy costs — net increased for the three months ended June 30, 2004 compared to the same period in 2003 because actual fuel and purchased power costs exceeded amounts recovered through rates to a lesser extent during the three month period in 2004 compared to 2003. During periods when actual fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as a reduction in costs. Deferred energy costs — net also increased for the three months ended June 30, 2004 as a result of a contract termination liability settlement during the second quarter of 2004 for a lesser amount than was originally recorded in June 2003. Finally, deferred energy costs — net increased as a result of higher amortization of prior deferred costs pursuant to the PUCN decision in NPC’s 2002 deferred energy rate case that resulted in increased rates beginning May 19, 2003, as a result of the amortization.

Deferred energy costs — net for the six months ended June 30, 2004, was comparable to the same period in 2003. During 2004, deferred energy costs — net decreased as a result of actual fuel and purchased power costs exceeding costs recovered through rates. Substantially offsetting this reduction in deferred energy costs — net was greater amortization during 2004 of prior deferred energy costs and the settlement of a terminated contract, as discussed above.

See Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies for more information regarding deferred energy accounting.

Allowance For Funds Used During Construction (AFUDC)


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Allowance for other funds used during construction	$	625	$	483		29.4	%	$	1,282	$	1,641		-21.9	%
Allowance for borrowed funds used during construction	$	776	$	520		49.2	%	$	1,706	$	1,576		8.3	%

	$	1,401	$	1,003		39.7	%	$	2,988	$	3,217		-7.1	%

AFUDC is higher for the three month period ended June 2004 than the same period in 2003 due to an increase in the AFUDC rate. The annual rate increased from 8.37% to 9.03% effective April 2004 as a result of NPC’s General Rate Case. AFUDC is lower for the six month period ended June 2004 compared to the same period in 2003 as a result of a decrease in the Construction Work in Progress (CWIP) balance on which AFUDC is calculated. The decrease is primarily due to Transmission and Distribution (Centennial and Crystal) projects being placed in service in 2004.

Other (Income) and Expenses


	Three Months									Six Months
	Ended June 30,									Ended June 30,
							Change from									Change from
	2004			2003			Prior Year %			2004			2003			Prior Year %
Other operating expense	$	50,913		$	51,675			-1.5	%	$	90,635		$	92,215			-1.7	%
Maintenance expense	$	16,790		$	15,650			7.3	%	$	36,746		$	29,187			25.9	%
Depreciation and amortization	$	29,991		$	26,714			12.3	%	$	58,730		$	52,621			11.6	%
Income tax expense/(benefit)	$	5,339		$	(16,274	)		N/A		$	(6,114	)	$	(26,822	)		-77.2	%
Interest charges on long-term debt	$	37,683		$	32,838			14.8	%	$	74,834		$	66,850			11.9	%
Interest charges-other	$	5,241		$	5,914			-11.4	%	$	9,828		$	11,994			-18.1	%
Interest accrued on deferred energy	$	(4,798	)	$	(5,234	)		-8.3	%	$	(10,193	)	$	(10,944	)		-6.9	%
Disallowed merger costs	$	—		$	—			N/A		$	3,961		$	—			N/A
Other income	$	(5,389	)	$	(4,136	)		30.3	%	$	(11,129	)	$	(7,591	)		46.6	%
Other expense	$	1,487		$	1,618			-8.1	%	$	2,928		$	3,050			-4.0	%
Income taxes — other income and expense	$	3,057		$	2,679			14.1	%	$	5,045		$	5,193			-2.9	%

The decrease in Other operating expense for the three and six month periods ended June 30, 2004 from comparable periods in 2003 was primarily due to higher reserves booked in the prior year periods to cover uncollectible accounts. Additional factors include less regulatory support and advisor fees in 2004.

Maintenance costs for the three and six month periods ended June 30, 2004 increased from the prior year due to the timing of scheduled and unscheduled plant maintenance at Clark Station, Sunrise and Reid Gardner.

Depreciation and amortization expense increased for the three month and six month periods ended June 30, 2004 compared to the same periods in 2003 as a result of an increase to plant-in-service. The three month increase is primarily a result of Transmission and Distribution (Centennial, Crystal 500KV Sub Expansion) projects which were placed in service effective April and May 2004, respectively.

NPC recognized income tax expense for the three-months ended June 30, 2004, compared to an income tax benefit during the comparable period in 2003. Also, a smaller tax benefit was recognized for the six-months ended June 30, 2004, compared to 2003. These changes are primarily a result of pre-tax operating income recognized during the second quarter of 2004 compared to operating losses during the same period in 2003. During the first six months of 2004, NPC recognized higher operating revenues and a decrease in fuel and purchased power expenses. Also contributing to the change from 2004 to 2003 was the recognition in the second quarter of 2003 of a reduction in estimated taxes payable.

Interest charges on Long-Term Debt for the quarter and six-months ended June 30, 2004 increased over the comparable periods in 2003 due primarily to the issuance in August 2003 of $350 million General and Refunding Bonds at an interest rate of 9.00%, which was partially offset by debt redemptions, in September 2003, of $210 million and $140 million. See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt for additional information regarding long-term debt.

Interest charges-other for the quarter and six-months ended June 30, 2004 decreased, compared to the same periods in 2003, due primarily to decreased interest charges related to terminated power and fuel contracts and a decrease in charges related to credit facilities. An increase in debt issuance costs related to increased debt partially offset the decreases.

Interest accrued on deferred energy costs for the three- and six-months ended June 30, 2004 decreased slightly, from the comparable periods in 2003 due to lower deferred fuel and purchased power balances. (Refer to Regulation and Rate Proceedings for further discussion of deferred energy accounting issues).

Disallowed merger costs expense for the six months ended June 30, 2004, includes the write-off of costs that resulted from the July 28, 1999 merger between SPR and NPC which were determined to be not recoverable through rates in the March 26, 2004, PUCN decision on NPC’s 2003 general rate case. The PUCN decision permitted substantially all of the merger costs that NPC requested recovery of except for a 20% reduction in goodwill and other merger costs that were to be amortized over the next two years. Also included in the write-off, are merger costs allocable to non-Nevada jurisdictional sales that NPC has determined will not be recovered in rates. See Regulatory Proceedings (Utilities) — Nevada Power Company 2003 General Rate Case and Note 11 in the Condensed Notes to Consolidated Financial Statements, Goodwill for additional information regarding NPC’s recovery of merger costs.

NPC’s Other income increased for the three- and six-months ended June 30, 2004, compared to the same periods in 2003 due to the recognition of revenue from the disposition of the Flamingo Corridor and other non-utility property. See Note 19, Discontinued Operations and Disposal and Impairment of Long-Lived Assets, Other Property Disposals in Form 10-K for the year ended 2003.

Income taxes-other income and expense increased slightly for the quarter ended June 30, 2004 compared to the same quarter in 2003 due to an increase in miscellaneous non-operating income. For the six-month period ended June 30, 2004, income taxes-other income and expense were comparable to the same period in 2003.

ANALYSIS OF CASH FLOWS

NPC’s cash flows were less during the six months ended June 30, 2004, compared to the same period in 2003 resulting primarily from decreases in cash flows from operating activities and financing activities, partially offset by a decrease in cash used in investing activities. The decrease in cash from operating activities is primarily due to the cash payment of $49 million to the Enron escrow account, fuel and purchased power costs exceeding our collection in rates of those costs, both during 2004, and increased collection efforts. Increased collection efforts, initiated in 2003, significantly decreased NPC’s accounts receivable balance as of December 2003 compared to December 2002. Partially offsetting these decreases were NPC’s requirement to prepay energy costs in 2003 due to NPC’s credit ratings and increased revenues in 2004 due to rate increases effective April 1, 2004. The decrease in cash from financing activities is primarily due to a $20 million dividend paid to SPR. Cash used in investing activities decreased mainly due to a decrease in utility construction.

LIQUIDITY AND CAPITAL RESOURCES

NPC had cash and cash equivalents of approximately $13 million at June 30, 2004.

NPC anticipates capital requirements for construction costs in 2004 will be approximately $473 million, including the recently announced Moapa Energy Facility discussed below, which NPC expects to finance with internally generated funds, including the recovery of deferred energy and new secured debt.

Moapa Energy Facility Financing Plan

Ongoing construction requirements are expected to be met with a combination of internal cash generation and the new revolving credit facility. Over the plan period, NPC’s internally generated cash contributions will represent an equity investment in the facility, with the intention to finance the plant approximately 50 percent with equity and 50 percent with long-term debt. See Nevada Power Company Second Amendment to its 2003 Resource Plan under Regulatory Proceedings (Utilities).

Accounts Receivable Facility

On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million. On May 4, 2004, NPC delivered a notice of termination of its accounts receivable facility in connection with the establishment of its revolving credit facility. The termination was effective on May 19, 2004.

Mortgage Indentures

NPC’s Indenture of Mortgage, dated as of October 1, 1953, between NPC and Deutsche Bank Trust Company Americas (the “First Mortgage Indenture”), creates a first priority lien on substantially all of NPC’s properties. As of June 30, 2004, $372.5 million of NPC’s first mortgage bonds were outstanding. In connection with the issuance of its Series E, Series G and Series I Notes NPC agreed that it would not issue any more first mortgage bonds.

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

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

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

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.

NPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of NPC’s properties in Nevada that is junior to the lien of the first mortgage indenture. As of June 30, 2004, $1.4 billion of NPC’s General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

1. 70% of net utility property additions,

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

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

On the basis of (1), (2) and (3) above, as of June 30, 2004, NPC had the capacity to issue approximately $729 million of additional General and Refunding Mortgage securities.

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

NPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of securities issuable under that indenture.

Financing Transactions

General and Refunding Mortgage Notes, Series I

On April 7, 2004, NPC issued and sold $130 million of its 6 1/2% General and Refunding Mortgage Notes, Series I, due April 15, 2012 that were issued with registration rights. The proceeds of the issuance were used to pay off $130 million aggregate principal amount of NPC’s 6.20% Series B, Senior Notes due April 15, 2004.

The terms of the Series I Notes, as with 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 I Notes, the Series G Notes and the Series H Bond, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan.

Revolving Credit Facility

On May 4, 2004, NPC established a $100 million Revolving Credit Facility which matures May 4, 2009. Borrowings under this facility will be evidenced on NPC’s General and Refunding Mortgage Bond, Series J, due 2009. The new Revolving Credit Facility replaces the previous Accounts Receivable Credit Facility, which was terminated on May 19, 2004.

NPC may, from time to time, access this facility for loans in increments of $1 million up to the limit of the facility. The rate for outstanding loans will be London Interbank Offered Rate (LIBOR) plus an applicable margin of 2.5%. On June 30, 2004, NPC drew upon this new Revolving Credit Facility for $10 million to meet necessary liquidity needs for ongoing operations. NPC’s cash balance at the end of June was $13 million, which includes the $10 million drawn on the revolving credit facility. NPC repaid its outstanding borrowings on August 4, 2004.

This Revolving Credit Facility, similar to earlier General and Refunding Mortgage Notes outlined below, contains various covenants and restrictions.

The Revolving Credit Facility restricts 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 credit agreement, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, certain letters of credit issued to support NPC’s obligations with respect to energy suppliers, and indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan.

Cross Default Provisions

Certain financing agreements of NPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of NPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, NPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in NPC’s various financing agreements are summarized below:

• NPC’s General and Refunding Mortgage Indenture, under which NPC has $1.4 billion of securities outstanding as of June 30, 2004, provides for an event of default if a matured event of default under NPC’s First Mortgage Indenture occurs; and

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

Judgment Related Defaults

The terms of NPC’s $250 million Series E, $350 million Series G and $130 million Series I General and Refunding Mortgage Notes, $186 million Series H General and Refunding Mortgage Bond and Revolving Credit Facility, provide for an event of default if a final, unstayed judgment in excess of $15 million is rendered against NPC and remains undischarged for 60 days. Since the Series E, Series G and Series I Notes and Series H Bond were issued under NPC’s General and Refunding Mortgage Indenture and NPC’s revolving credit facility is supported by a General and Refunding Mortgage Bond, a default under any of the Series E, Series G and Series I Notes, Series H Bond and Revolving Credit Facility, will trigger a default under NPC’s General and Refunding Mortgage Indenture.

Indenture; therefore, NPC would be unable to provide certain required opinions of counsel to issue additional securities under its General and Refunding Mortgage Indenture until the judgment lien is discharged and released. Since NPC is unable to issue additional bonds under its First Mortgage Indenture, its sole means of issuing secured debt is through its General and Refunding Mortgage Indenture.

Limitations on Indebtedness

The terms of NPC’s Series E Notes, which mature in 2009, NPC’s Series G Notes, which mature in 2013, NPC’s Series I Notes, which mature in 2012, NPC’s Series H Bond and NPC’s revolving credit facility 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, which includes limited amounts of debt with respect to certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, certain letters of credit issued to support NPC’s obligations with respect to energy suppliers, and for the Series G Notes, Series I Notes, the Series H Bond and the revolving credit facility indebtedness to finance capital expenditures incurred pursuant to NPC’s 2003 IRP.

If NPC’s Series E Notes, Series G Notes, Series I Notes or the 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 securities remains investment grade.

Contractual Obligations

In addition, the PUCN conducted hearings on NPC’s IRP on October 16, 2003. The PUCN approved an order on NPC’s IRP on November 12, 2003. In general, the order approved NPC’s various requests made in its filing and also imposed additional requirements for various briefings, and required amendments to the IRP if there are delays in the construction of the combined cycle units, issues with transmission reservations, or difficulties financing the IRP. As such, NPC may need to expend up to approximately $500 million prior to the summer of 2007 for the construction and/or acquisition of generation facilities.

Consistent with the above anticipated need for new generation, on June 29, 2004 NPC filed with the PUCN, in connection with the purchase of the Moapa energy facility from Duke Energy, a 2nd Amendment to the NPC Integrated Resource Plan and an associated $500 million financing application. Please refer to the Moapa Energy Facility Financing Plan section for a further discussion of this financing plan.

During the six months ended June 30, 2004, there were no material changes, outside the ordinary course of NPC’s business, to contractual obligations as set forth in NPC’s 2003 10-K.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2004, SPPC incurred a net loss applicable to common stock of approximately $33.2 million compared to $28.9 million for the same period in 2003. During the six months ended June 30, 2004, SPPC incurred a net loss of approximately $26.5 million compared to $25.9 million for the same period in 2003. For the six months ended June 30, 2004 SPPC declared and paid $1.95 million in dividends to holders of its preferred stock and neither declared nor paid dividends on its common stock, all of which is held by its parent, SPR. In August 2004, SPPC declared a dividend of $975,000 to holders of its preferred stock.

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


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change								Change
					from Prior								from Prior
	2004		2003		Year %			2004			2003		Year %
Operating Revenues:
Electric	$	202,425	$	205,026		–1.3	%	$	404,266		$	410,480		–1.5	%
Gas		21,879		35,873		–39.0	%		81,355			100,490		–19.0	%

	$	224,304	$	240,899		–6.9	%	$	485,621		$	510,970		–5.0	%

Energy Costs:
Purchased Power	$	71,758	$	75,674		–5.2	%	$	137,718		$	162,852		–15.4	%
Fuel for Power generation		53,797		47,559		13.1	%		107,599			81,235		32.5	%
Deferred energy costs disallowed		—		45,000		N/A			—			45,000		N/A
Deferral of energy costs-electric-net		134		7,241		–98.2	%		4,705			18,643		–74.8	%
Gas purchased for resale		14,482		27,865		–48.0	%		62,399			70,199		–11.1	%
Deferral of energy costs-gas-net		1,376		1,020		34.9	%		(31	)		11,823		–100.3	%

		141,547		204,359		–30.7	%		312,390			389,752		–19.8	%

Energy Costs by Segment:
Electric	$	125,689	$	175,474		–28.4	%	$	250,022		$	307,730		–18.8	%
Gas		15,858		28,885		–45.1	%		62,368			82,022		–24.0	%

	$	141,547	$	204,359		–30.7	%	$	312,390		$	389,752		–19.9	%

Gross Margin by Segment:
Electric	$	76,736	$	29,552		159.7	%	$	154,244		$	102,750		50.1	%
Gas		6,021		6,988		–13.8	%		18,987			18,468		2.8	%

	$	82,757	$	36,540		126.5	%	$	173,231		$	121,218		42.9	%

Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.

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

Electric Operating Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2004		2003		year %			2004		2003		year %
Electric Operating Revenues:
Residential	$	49,676	$	52,391		–5.2	%	$	112,636	$	112,260		0.3	%
Commercial		70,036		68,737		1.9	%		134,909		131,865		2.3	%
Industrial		70,568		68,750		2.6	%		137,124		134,928		1.6	%

Retail		190,280		189,878		0.2	%		384,669		379,053		1.5	%
Other (1)		12,145		15,148		–19.8	%		19,597		31,427		–37.6	%

Total Revenues	$	202,425	$	205,026		–1.3	%	$	404,266	$	410,480		–1.5	%

Retail sales in thousands of MWh		2,180		2,166		0.7	%		4,413		4,300		2.6	%
Average retail revenue per MWh	$	87.28	$	87.66		–0.4	%	$	87.17	$	88.15		–1.1	%

(1) Primarily Economy Energy and Firm Wholesale Sales, as discussed below

SPPC’s residential retail revenues decreased for the three months ending June 30, 2004 as compared to the same period in the prior year due to a decrease in customer usage from cooler temperatures in May and June 2004. The slight increase in residential retail revenues for the six months ending June 30, 2004 when compared to the same period in the prior year is due to colder temperatures in January 2004 offset by the mild temperatures in the second quarter 2004. Commercial and Industrial revenues for the three and six month periods ending June 30, 2004 were comparable to the same periods in the prior year.

Management expects a slight increase in revenues for the remainder of 2004 due to an increase in Nevada customer rates as a result of SPPC’s General Rate Case, effective June 1, 2004, an increase in Nevada customer energy rates effective July 15, 2004 as a result of SPPC’s Deferred Energy Case, and continued customer growth.

The decrease in Electric Operating Revenues-Other for the three and six months ending June 30, 2004, compared to the same periods in 2003, was primarily due to the decrease in sales volume of wholesale electric power to other utilities and a reduction in sales associated with risk management activities. See the 2003 10-K, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Purchased Power Procurement, for a discussion of SPPC’s purchased power procurement strategies.

Gas Operating Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2004		2003		year %			2004		2003		year %
Gas Operating Revenues
Residential	$	10,692	$	14,280		–25.1	%	$	42,078	$	42,905		–1.9	%
Commercial		5,888		7,451		–21.0	%		21,520		21,725		–0.9	%
Industrial		2,222		3,192		–30.4	%		6,268		8,032		–22.0	%

Retail revenue		18,802		24,923		–24.6	%		69,866		72,662		–3.8	%
Wholesale revenue		2,389		10,217		–76.6	%		10,001		26,593		–62.4	%
Miscellaneous		688		733		–6.1	%		1,488		1,235		20.5	%

Total Revenues	$	21,879	$	35,873		–39.0	%	$	81,355	$	100,490		–19.0	%

Retail sales in thousands of decatherms		1,926		2,531		–23.9	%		7,487		7,561		–1.0	%
Average retail revenues per decatherm	$	9.76	$	9.85		–0.9	%	$	9.33	$	9.61		–2.9	%

Retail gas revenues decreased for the three and six months ending June 30, 2004 from the same periods in 2003 primarily due to a decrease in customer usage resulting from warmer temperatures in March and April 2004. Additionally, a decrease in energy related rates that became effective November 1, 2003 contributed to the decline in retail gas revenues. This decrease in the energy related rates was the result of SPPC’s Purchased Gas Adjustment filing (see Regulatory Proceedings in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2003 10-K). The decrease in industrial retail revenues was attributable to a shift of industrial customers to SPPC’s gas transportation tariff.

Wholesale gas revenues for the three and six month periods ending June 30, 2004 decreased from the same periods in 2003 primarily due to a decrease in the utilization of idle gas transportation capacity to move gas from Canada to California for resale. The margins associated with utilization of transportation capacity decreased in 2004 compared to 2003, as management determined it was less favorable to enter into such transactions. The decline in revenues was partially offset by an increase in pipeline capacity sales.

Purchased Power


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2004		2003		Year %			2004		2003		Year %
Purchased Power	$	71,758	$	75,674		–5.2	%	$	137,718	$	162,852		–15.4	%
Purchased Power in thousands of MWhs		1,429		1,624		–12.0	%		2,633		3,216		–18.1	%
Average cost per MWh of Purchased Power	$	50.22	$	46.60		7.8	%	$	52.30	$	50.64		3.3	%

Purchased power costs were lower for the three months and six-months ended June 30, 2004, compared to the same periods in 2003. While short-term energy prices increased slightly, volumes were lower for both the three and six month periods. The decrease in volumes is due to SPPC satisfying more of its load requirements through its own generation. See Fuel for Power Generation that follows.

Fuel For Power Generation


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2004		2003		Year %			2004		2003		Year %
Fuel for Power Generation	$	53,797	$	47,559		13.1	%	$	107,599	$	81,235		32.5	%
Thousands of MWh generated		1,060		937		13.1	%		2,243		1,884		19.1	%
Average fuel cost per MWh of Generated Power	$	50.75	$	50.76		N/A		$	47.97	$	43.12		11.2	%

The cost of fuel for power generation increased for the three months and six months ended June 30, 2004 compared to the same periods in 2003 predominately due to an increase in the volume of internal generation. Fuel for power generation for the six months ended June 30, 2004, also increased due to increased fuel prices.

Gas Purchased for Resale


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2004		2003		Year %			2004		2003		Year %
Gas Purchased for Resale	$	14,482	$	27,865		–48.0	%	$	62,399	$	70,199		–11.1	%
Gas Purchased for Resale (in thousands of decatherms)		1,980		4,954		–60.0	%		9,210		12,575		–26.8	%
Average cost per decatherm	$	7.31	$	5.62		30.1	%	$	6.78	$	5.58		21.5	%

The cost of gas purchased for resale decreased for the three months and six months ended June 30, 2004 compared to the same periods in 2003 primarily due to a decrease in volume. The decrease in volume is attributable to the decline in wholesale revenues due to the decrease in the utilization of idle gas transportation capacity to move gas from Canada to California for resale. The decrease in volume was partially offset by increased gas prices for the three and six months ended June 30, 2004.

Deferred Energy Costs


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change								Change
					from Prior								from Prior
	2004		2003		Year %			2004			2003		Year %
Deferred energy costs disallowed	$	—	$	45,000		–100.0	%	$	—		$	45,000		–100.0	%
Deferred energy costs – electric – net		134		7,241		–98.1	%		4,705			18,643		–74.8	%
Deferred energy costs – gas – net		1,376		1,020		34.9	%		(31	)		11,823		–100.3	%

Total	$	1,510	$	53,261		–97.2	%	$	4,674		$	75,466		–93.0	%

Deferred energy costs disallowed for the three and six months ended June 30, 2003, represents a write-off effective June 1, 2003, of $45 million pursuant to a stipulation approved by the PUCN in Docket 03-1014.

The decrease in deferred energy costs — electric — net for the three and six months ended June 30, 2004, compared to the same periods in 2003, is due to actual fuel and purchased power costs exceeding recovery of those costs through current rates to a greater extent during 2004, and a decrease in the amortization of prior deferred energy costs in 2004 compared to 2003. During periods when actual fuel and purchase power costs exceed the amounts recovered through rates, the excess costs are shown as a reduction.

SPPC’s Deferred energy costs — gas — net increased for the three months ended June 30, 2004, primarily as a result of costs being recovered through current rates in 2004 in excess of actual gas cost, which was not the case in 2003, and lower amortization of prior deferred gas costs during 2004 compared to 2003. However, for the six months ended June 30, 2004, a net decrease in deferred energy costs-gas-net resulted from actual natural gas prices exceeding the recovery of those costs through current rates during 2004, but not during 2003. Also, during 2004 amortization of prior deferred gas costs were lower than during 2003.

Allowance For Funds Used During Construction (AFUDC)


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change							Change
					from Prior							from Prior
	2004		2003		Year %			2004		2003		Year %
Allowance for other funds used during construction	$	567	$	601		–5.7	%	$	1,283	$	1,203		6.7	%
Allowance for borrowed funds used during construction	$	891	$	611		45.8	%	$	2,134	$	1,311		62.8	%

	$	1,458	$	1,212		20.3	%	$	3,417	$	2,514		35.9	%

AFUDC was higher for the three month and six month periods ended June 2004 compared to the same periods in 2003 due to increased construction costs primarily related to the Falcon-Gonder transmission project included in the Construction Work in Progress (CWIP) balance. The Falcon-Gonder transmission project was placed into service during the quarter ended June 2004, as such management believes future AFUDC costs will be significantly less than prior periods.

Other (Income) and Expenses


	Three Months									Six Months
	Ended June 30,									Ended June 30,
							Change									Change
							from Prior									from Prior
	2004			2003			Year %			2004			2003			Year %
Other operating expense	$	32,891		$	31,625			4.0	%	$	63,702		$	60,838			4.7	%
Maintenance expense	$	5,426		$	6,453			–15.9	%	$	10,358		$	11,640			–11.0	%
Depreciation and amortization	$	22,138		$	19,961			10.9	%	$	43,336		$	39,667			9.3	%
Income tax expense/(benefit)	$	(571	)	$	(18,298	)		–96.9	%	$	305		$	(16,208	)		N/A
Interest charges on long-term debt	$	17,847		$	18,959			–5.9	%	$	36,715		$	37,740			–2.7	%
Interest charges-other	$	2,470		$	2,604			–5.1	%	$	4,627		$	5,729			–19.2	%
Interest accrued on deferred energy	$	(1,183	)	$	(1,589	)		–25.6	%	$	(2,337	)	$	(3,514	)		–33.5	%
Other income	$	(896	)	$	(1,035	)		–13.4	%	$	(1,756	)	$	(2,100	)		–16.4	%
Disallowed merger costs	$	—		$	—			N/A		$	1,929		$	—			N/A
Plant costs disallowed	$	47,092		$	—			N/A		$	47,092		$	—			N/A
Other expense	$	1,242		$	1,702			–27.0	%	$	2,555		$	3,607			–29.2	%
Income taxes — other income and expense	$	(15,035	)	$	476			N/A		$	(15,358	)	$	779			N/A

Other operating expense for the three and six month periods ending June 30, 2004 was comparable to the same period in the prior year.

Maintenance costs for the three and six month periods decreased by several items, none of which were individually significant.

Depreciation and amortization expense increased for the three month and six month periods ended June 2004 compared to the same periods in 2003 as a result of an increase to plant-in-service and an increase in depreciation rates approved by the California Public Utilities Commission (CPUC) effective January 2004. In the second quarter of 2004, SPPC placed into service the Falcon — Gonder transmission project. As a result, management expects there will be an increase in depreciation and amortization expense for the remainder of the year.

SPPC recognized higher income taxes for the three and six months ended June 30, 2004, compared to the same periods during 2003 substantially as a result of the tax benefit recognized from $45 million of deferred energy costs disallowed during the second quarter of 2003. Also contributing to the change from 2004 to 2003 was the recognition in the second quarter of 2003 of a reduction in estimated taxes payable.

SPPC’s interest charges on long-term debt decreased slightly during the three- and six-months ended June 30, 2004 from the comparable periods in 2003, following lower balances in its long-term debt as a result of the redemption, in 2003, of $18.5 million debt.

SPPC’s interest charges-other for the three and six-months ended June 30, 2004 was comparable to the same periods in 2003.

Interest accrued on deferred energy costs decreased for the three and six months ended June 30, 2004 compared to the same periods 2003 due to lower deferred fuel and purchased power balances during 2004. (Refer to Regulatory Proceedings (Utilities) for discussion of deferred energy issues).

SPPC’s Other income decreased slightly during the three and six months ended June 30, 2004 from the comparable periods in 2003 due, primarily, to lower interest income.

Disallowed merger costs expense for the six months ended June 30, 2004, includes the write-off of costs that resulted from the merger between SPR and NPC, allocable to non-Nevada jurisdictional electricity sales, which were determined not to be recoverable in future rates. See Regulatory Proceedings (Utilities) — Sierra Pacific Power Company 2003 General Rate Case.

SPPC’s Plant costs disallowed is the result of the decision of the PUCN to disallow recovery of a portion of the costs associated with the Piñon Pine power plant project (See Note 4 for a discussion of Regulatory Proceedings).

SPPC’s Other expense decreased for the quarter ended June 30, 2004 compared to the same period in 2003 due, primarily, to reductions in charges related to SPPC’s advertising and lobbying activities, and charges related to SPPC’s general office building.

Income taxes – other income and expense changed from income tax expense recognized for the three and six-months ended June 30, 2003, to income tax benefits recognized during the same periods in 2004. The 2004 tax benefit was recognized primarily as a result of an impairment charge associated with the Piñon Pine generating facility during the second quarter of 2004. See Note 4 in the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for additional information regarding the impairment charge.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows during the six months ended June 30, 2004 compared to the same period in 2003 decreased as a result of a decrease in cash flows from financing activities and operating activities. This decrease was partially offset by a decrease in cash used in investing activities. Cash flows used in financing activities increased due to the repayment of $25 million in short-term borrowing in March 2004. Cash flows from operating activities decreased primarily as a result of the cash payment of $11 million to the Enron escrow account as required by the Enron Judgment. See Note 9 of the Condensed Notes to Consolidated Financial Statements, commitments and Contingencies. Additionally, the decrease of cash flows from operating activities was the result of fuel and purchased power costs exceeding our collection in rates of those costs and increased collection efforts. Increased collection efforts, initiated in 2003, significantly decreased SPPC’s accounts receivable balance as of December 2003 compared to December 2002. Partially offsetting these decreases in cash from operating activities were SPPC’s requirement to prepay energy costs in 2003 due to SPPC’s credit. Cash flows from investing activities decreased primarily as a result of decreased construction activity as the Falcon to Gonder project was completed in 2004.

LIQUIDITY AND CAPITAL RESOURCES

SPPC had cash and cash equivalents of approximately $16 million at June 30, 2004.

SPPC anticipates capital requirements for construction costs during 2004 totaling approximately $108 million, which SPPC expects to finance with internally generated funds, including the recovery of deferred energy.

Accounts Receivable Facility

On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million. On May 4, 2004, SPPC delivered a notice of termination of its accounts receivable facility in connection with the establishment of its Revolving Credit Agreement. The termination was effective on May 19, 2004.

Mortgage Indentures

SPPC’s First Mortgage Indenture creates a first priority lien on substantially all of SPPC’s properties in Nevada and California. As of June 30, 2004, $487.3 million of SPPC’s first mortgage bonds were outstanding. SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds.

SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s properties in Nevada that is junior to the lien of the first mortgage indenture. As of June 30, 2004 there were $642 million of SPPC’s General and Refunding Mortgage securities outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

1. 70% of net utility property additions,

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

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

On the basis of (1), (2) and (3) above, as of June 30, 2004, SPPC had the capacity to issue approximately $381 million of additional General and Refunding Mortgage securities.

Although SPPC has substantial capacity to issue additional General and Refunding Mortgage securities on the basis of property additions and retired securities, the financial covenants contained in the Revolving Credit Agreement limit the amount of additional indebtedness that SPPC may issue and the reasons for which such indebtedness may be issued.

SPPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture.

Financing Transactions

Short-Term Financing

General and Refunding Mortgage Notes, Series H

On April 16, 2004, SPPC issued and sold $100 million of its 61/4% General and Refunding Mortgage Notes, Series H, due April 15, 2012. The Series H Notes were issued with registration rights. The proceeds of the issuance along with operating cash were used to substantially pay off SPPC’s 10.5% Term Loan Facility, due October 2005.

The terms of the Series H Notes also restrict SPPC from incurring any additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’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 Series H Notes, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, or

3. indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Integrated Resource Plan.

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

Water Facilities Refunding Revenue Bonds

On May 3, 2004, SPPC’s $80 million Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest rate on the bonds was adjusted from their prior one year 7.50% term rate to a 5.0% term rate for the period of May 3, 2004 to and including July 1, 2009. The bonds will be subject to remarketing on July 1, 2009. 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 3, 2004 to and including July 1, 2009, SPPC’s payment and purchase obligations in respect of the bonds are secured by SPPC’s $80 million General and Refunding Mortgage Note, Series J, due 2009.

Revolving Credit Facility

This Revolving Credit Facility, similar to the Series H Notes outlined above, contain various covenants and restrictions.

The Revolving Credit Facility restricts SPPC from incurring any additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’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 Credit Agreement, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, and indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Integrated Resource Plan.

Among other things, the Revolving Credit Facility also contains restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. There are also limitations on certain fundamental structural changes to SPPC and limitations on the disposition of property.

Cross Default Provisions

Certain financing agreements of SPPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPPC’s various financing agreements are briefly summarized below:

• SPPC’s General and Refunding Mortgage Indenture, under which SPPC has $642 million of securities outstanding as of June 30, 2004, provides for an event of default if a matured event of default under SPPC’s First Mortgage Indenture occurs; and

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

Judgment Related Defaults

Limitations on Indebtedness

The terms of SPPC’s Series E Bond, Series H Notes and Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless the debt issued is specifically permitted, which includes certain letter of credit indebtedness, certain capital lease obligations, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, and a limited amount of general indebtedness.

If SPPC is unable to access the capital markets to issue additional indebtedness to support its operations, including the purchase of fuel and power, and to refinance its existing indebtedness, whether due to lack of access to the capital markets, lack of regulatory authority, and the restrictive covenants contained in its Series E Bond, Series H Notes and Revolving Credit Agreement, its ability to provide power and its financial condition will be adversely affected.

Contractual Obligations

During the six months ended June 30, 2004, there were no material changes, outside the ordinary course of SPPC’s business, to contractual obligations as set forth in SPPC’s 2003 10-K.

REGULATORY PROCEEDINGS (UTILITIES)

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

Under federal law, the Utilities 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 has similar jurisdiction over the natural gas pipeline companies like TGPC.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies. The following regulatory proceedings have affected, or are expected to affect the utilities financial positions, results of operations and cash flows.

Nevada Matters

Nevada Power Company 2003 General Rate Case

• Approximately $21.4 million of generation divestiture costs to be recovered over an extended period of 8 years;

• Approved the establishment of a regulatory asset account to capture costs related to the shutdown of the Mohave Power Plant.

On April 12, 2004, the BCP filed a petition with the PUCN requesting reconsideration and clarification of the Commission’s decision regarding three issues: 1) income taxes and liberalized depreciation, 2) the recovery of merger costs and 3) the proper accounting treatment of rental revenue associated with a property sold by NPC.

Nevada Power Company 2003 Deferred Energy Case

On November 14, 2003, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between October 1, 2002 and September 30, 2003, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $93 million. On March 26, 2004, the PUCN granted approval for NPC to increase its going forward energy rate as filed, approved recovery for $89 million of its deferred balance, denied $4 million, and denied NPC’s request for a tax gross-up on the equity portion of carrying charges. Of the $4 million disallowed only $1.6 million was charged to income in the current period as the remaining amount had no impact on earnings or was charged to income in prior periods. The PUCN ordered the change in going forward rates to take effect April 1, 2004 and delayed the implementation of the deferred energy balance recovery until January 1, 2005 when the 2001 deferred balance is expected to have been completed.

Nevada Power Company Additional Finance Authority

NPC Application for $230 Million Long-Term Debt Authority

NPC Application for $500 Million Long-Term Debt Authority

See Moapa Energy Facility Financing Plan under NPC’s Liquidity and Capital Resources Section.

Nevada Power Company Second Amendment to its 2003 Resource Plan

NPC filed an amendment to its 2003 Resource Plan on June 29, 2004. The amendment requests PUCN authorization to acquire a partially completed power plant, the “Moapa Energy Facility”, from Duke Energy for $182 million. This amendment requests approval to substitute the 1200 MW Moapa Energy Facility, which is expected to become operational in early 2006, for the previously approved Harry Allen 520 MW combined cycle generator, which was to come on line in 1997.

Sierra Pacific Power Company 2003 General Rate Case

The parties also reached a stipulated agreement that resolved the rate design issues in the case.

On May 27, 2004, the PUCN issued an order accepting the two stipulations, discussed above, and responding to SPPC’s request for recovery of the Piñon investments. The PUCN permitted recovery of approximately $37 million (Nevada jurisdictional) of the costs plus a carrying charge to be amortized over 25 years and approximately $11 million (Nevada jurisdictional) of costs without a carrying charge to be amortized over 10 years. The PUCN order granted a $46.7 million increase to SPPC’s general revenues.

Sierra Pacific Power Company 2004 Deferred Energy Case

energy balance of approximately $42 million, which would result in recovery of $8 million effective July 2004; $17 million effective July 2005; and $17 million effective July 2006. The Application also requested a deviation from regulation in resetting the BTER (Base Tariff Energy Rate). That methodology and its results would result in no change to the currently effective BTER.

On July 7, 2004, the PUCN ruled on the deferred energy case, and approved a full recovery of the fuel and purchased power costs. The PUCN order delayed the start of the deferred balance recovery until April 2005, which corresponds with the expected repayment of previous deferred balances. The PUCN also ordered SPPC to implement a higher BTER rate (the rate paid for going forward energy purchases) than that requested by the Company. The higher BTER rate represents an overall increase of 4.4 percent in electric rates for SPPC and became effective July 15, 2004.

Sierra Pacific Power Company Additional Finance Authority

SPPC Application for $230 Million Long-Term Debt Authority

Sierra Pacific Power Company 2004 Resource Plan

SPPC filed its triennial resource plan with the PUCN on July 1, 2004. The significant provisions of the plan include efforts to minimize SPPC’s reliance on a volatile energy market through a mix of owned generation, fuel diversity and purchased power. Consistent with this plan is a request for approval to construct a 500 MW combined cycle plant at SPPC’s Tracy generation station to be in service in 2008 and to conduct the permitting and development activities necessary to construct an additional 250 MW coal-fired unit at Valmy to be placed in service in the 2011 to 2015 time frame. SPPC will fill its remaining open position with purchased power from renewable energy providers and non-renewable sources.

Additionally SPPC is seeking PUCN approval on the following items:

• Designation of the combined cycle plant as “critical facility” in accordance with the PUCN’s regulations which allows for an enhanced return on equity on the designated “critical facility” over the life of the facility. The Tracy facility qualifies as a “critical facility” under the PUCN’s recently amended resource planning regulations because it promotes price stability and reliability and reduces dependence on purchased power.

• Approval to upgrade the combustion systems at SPPC’s Valmy generating station to comply with the emission standards of the “Clear Skies Initiative”.

• Approval to conduct a study on the feasibility of additional coal-fired generation at SPPC’s Valmy generation plant.

• Approval of the renewable energy promotion program through which SPPC will promote renewable energy development.

• Approval of SPPC’s energy supply plan for the period from 2005 through 2007. The energy supply plan includes a recommendation for the issuance of a request for proposals for short and intermediate term power contracts to fill a significant portion of SPPC’s capacity requirements during that period. The energy supply plan also includes a recommended gas hedging strategy for April 2005 through March 2006.

• Approval of the construction of a new 345 kV transmission line from SPPC’s existing East Tracy 345 kV substation to a new 345 kV substation (Emma) located east of Virginia City.

California Matters (SPPC)

On May 1, 2004, SPPC filed its annual Energy Cost Adjustment Clause (ECAC) in California. The filing updates its estimated fuel and purchase power costs for its California customers and seeks to recover or refund any deferred amounts projected through September 30, 2004. The filing requests $8.3 million or a 14.8% overall increase consisting of $3.9 million increase in the base rate and $4.4 million for the projected balance. A decision is expected in the third quarter of 2004 with rate changes implemented in the fourth quarter. On July 14, 2004, a pre-hearing conference was held to establish a procedural schedule.

Other Matters

Assembly Bill 661 – Retail Competition

In February 2004, Barrick, a large SPPC mining customer filed an AB661 application. Barrick intends to construct a generating facility to meet its electric power needs and will purchase transmission and distribution service from SPPC. Barrick, SPPC and other parties reached an agreement prior to hearings and it was presented to the PUCN on May 19, 2004. The PUCN issued an order approving the application as stipulated in the agreement on June 22, 2004.

Upon exiting, Barrick has agreed to pay a $10.75 million impact charge that will mitigate the impact of Barrick’s departure from bundled electric service and insure no economic harm to remaining customers of SPPC. Impact charge payments made by Barrick will be recorded in a regulatory asset account. Beginning upon Barrick’s departure and continuing until rates are set through SPPC’s next subsequent general rate proceeding, SPPC will record $.65 million monthly to the regulatory asset to reflect the reduction in generation revenues attributable to Barrick’s departure. Carrying charges equivalent to 1/12th of SPPC’s authorized cost of capital will be added monthly to the balance of the regulatory asset account. The net balance of the regulatory asset will be amortized and included in rates in SPPC’s next subsequent rate proceeding. The departure of Barrick is not expected to have a material impact on the results of operations of SPPC.

Barrick will also pay its share of Deferred Energy costs, estimated to be approximately $6 million at Barrick’s departure date. These costs are the fuel and purchased power costs attributable to serving Barrick, that will not have been collected as of Barrick’s departure date.

Barrick has agreed to sell approximately 8 megawatts of capacity from this new generation source to SPPC. If this contract is consummated as outlined in the stipulated agreement, Barrick’s impact charge will be reduced by $2.9 million.

By taking energy service from its own generating facility and other sources, Barrick will reduce kilowatt hour consumption on SPPC’s electric system by approximately 12% of Nevada retail sales. SPPC’s peak electric load has increased at an average annual rate of 3.1% over the past five years, while the company’s energy sales have grown at a compound annual growth rate of 2.4%. With Barrick generating its own power, this generating facility is anticipated to be operational by September 1, 2005; SPPC will reduce its power purchases.

Barrick must secure permits and negotiate agreements in preparation for exiting SPPC’s system before the PUCN will grant final approval of the application. Regulatory approvals from other agencies and final Barrick corporate approval are necessary before the associated generating plant is built.

The PUCN granted a conditional Utility Environmental Permit to Barrick on July 21, 2004. The permit allows Barrick to build a 118 MW natural gas generating facility near Tracy that will serve a portion of its power needs. The permit is conditional upon Barrick demonstrating to local, state and federal regulators that the project complies with all applicable environmental and land use laws.

Renewable Energy Portfolio Standard

Nevada Power Company

NPC filed a statutorily mandated compliance Renewable Portfolio report with the PUCN on April 1, 2004. NPC advised the PUCN that there were insufficient renewable supplies (solar and non-solar) available to meet the Renewable Portfolio Standard for 2003 and would likely not be able to meet the 2004 requirements for the same reason. NPC reported its efforts to meet the requirements and plans to comply in the future. NPC reached negotiated agreement with the parties and presented the agreement to the hearing officer on June 28, 2004. The agreement recognized that NPC attempted to acquire renewable energy to meet the 2003 requirements and has instituted measures to ensure compliance in future years. The stipulated agreement grants NPC an exemption from meeting the 2003 Portfolio Standards. The PUCN issued an order approving the agreement on July 21, 2004.

Sierra Pacific Power Company

SPPC filed a statutorily mandated compliance Renewable Portfolio report with the PUCN on April 1, 2004. SPPC reported to the PUCN that it exceeded its non-solar renewable requirements for 2003 and expected to exceed its non-solar renewable requirements for 2004. SPPC also advised the PUCN that there were insufficient solar supplies available to meet the Renewable Portfolio Standard for 2003 and would likely not be able to meet the 2004 requirements for the same reason. SPPC reported its efforts to meet the requirements and plans to comply in the future. SPPC reached negotiated agreement with

the parties and presented the agreement to the hearing officer on June 28, 2004. The agreement recognized that SPPC met its non-solar renewable requirements, attempted to acquire renewable energy to meet the 2003 requirements and has instituted measures to ensure compliance in future years. The agreement grants SPPC an exemption from meeting the 2003 Portfolio Standards. The PUCN issued an order approving the agreement on July 21, 2004.

TRED Trust

On July 9, 2004, NPC and SPPC together with the Regulatory Operations Staff of the PUCN, the Bureau of Consumer Protection, and certain renewable energy providers filed a joint petition with the PUCN requesting that Nevada regulations be amended to establish a Temporary Renewable Energy Development (TRED) program to assist with the completion of new renewable energy projects. It is anticipated that the TRED program will result in more renewable energy projects moving forward to completion, thereby allowing Nevada to satisfy renewable energy portfolio requirements. Specifically the TRED program would: (1) establish a TRED charge to separately collect revenue to pay for renewable energy; and (2) establish a TRED trust to receive the proceeds from the TRED Charge and remit payment to approved renewable energy projects that deliver renewable energy to the purchasing utility. The PUCN was requested to act expeditiously and is anticipated to act on this regulation as early as September 2004. The joint petitioners also plan to request 2005 legislative changes to: (1) affirm the PUCN’s authority to establish the TRED program; (2) address the conditions to be met before TRED program could be closed; and (3) assure the TRED program will not be repealed, amended or modified to impair, in any way, any renewable energy contract approved by the PUCN for participation in a TRED Program or any revenues from any such renewable energy contract for the duration of such contract. NPC and SPPC currently anticipate that their initial filing to establish a TRED charge would be filed concurrently with their next fuel and purchased power filing to be implemented in spring or summer 2005.

Open Access Transmission Tariff

On September 11, 2003, the Utilities filed with the FERC revised rates for transmission service offered by NPC under Docket No. ER03-1328. The purpose of the filing was to update rates to reflect recent transmission additions and to improve rate design. On November 7, 2003, FERC accepted the revised tariff sheets, made rates effective on November 10, 2003, subject to refund, and established hearing procedures. The active participants in the proceeding reached a settlement in principle of all issues. The Certification of Uncontested Offer of Settlement was issued on June 14, 2004. The FERC issued an Order approving the uncontested settlement on July 8, 2004 and requiring that any refunds due under the Settlement Agreement to be paid, with interest, within thirty (30) days. As a result of the approved settlement, NPC is obligated to refund approximately $5.9 million based on the revised FERC rates.

RECENT PRONOUNCEMENTS

In December 2003, the FASB issued Interpretation No. 46, as 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, SPR, NPC and SPPC adopted FIN 46(R) for special purpose entities. As of March 31, 2004, SPR, NPC and SPPC adopted FIN 46(R) for all variable interest entities. To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with qualifying facilities, jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven qualifying facilities (QFs) with long-term purchase power contracts that are variable interests. However, the Utilities are not required at this time to consolidate these QFs under the scope exception provided for in FIN 46(R) related to the inability to obtain information necessary to (1) determine whether the entity is a variable interest entity, (2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3) perform the accounting required to consolidate the variable interest entity for which it is determined to be the primary beneficiary. The Utilities have requested financial information from these QFs but have not been successful in obtaining the information. Our maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs are unable to deliver power. However, we believe our exposure is mitigated as we would likely recover these costs through our deferred energy accounting mechanism. We have not identified any other significant variable interests that require consolidation as of June 30, 2004.

FSP FAS 106-2

The FASB issued FASB Statement of Position (FSP) FAS 106-2 in May 2004 to provide guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, signed into law by the President on December 8, 2003. This FSP FAS 106-2 supersedes FSP FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, under which SPR elected to defer implementation due to the lack of definitive guidelines from the FASB and the Department of Health and Human Services.

SPR had tentatively concluded that its prescription drug plan would qualify for the federal subsidy under this Act. (Please refer to Note 1, Summary of Significant Accounting Policies in the Annual Report on Form 10-K for 2003.)

FSP FAS 106-2 applies only to sponsors of single-employer defined benefit postretirement health care plans for which (1) the employer has concluded that prescription drug benefits available under the plan to some or all participants, for some or all future years, are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy provided by the Act, and (2) the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. The FSP provides guidance on measuring the accumulated postretirement benefit obligation (APBO) and net periodic postretirement benefit cost, and the effects of the Act on APBO. In addition, the FSP addresses accounting for plan amendments, and requires certain disclosures about the Act and its effects on financial statements. The effect of the subsidy on the APBO for benefits attributable to past service will be accounted for as an actuarial experience gain pursuant to paragraphs 56 and 59 or 60 of Statement 106. Because the subsidy affects the employer’s share of its plan’s costs, the subsidy is included in measuring the costs of benefits attributable to current service. Therefore, the subsidy reduces service cost (as defined in paragraph 47 of SFAS No. 106) when it is recognized as a component of net periodic postretirement benefit cost. The FSP allows for either prospective recognition from the date of adoption or retroactive recognition by restating prior quarters for the effect of the change. The latter treatment will allow for the recognition of the cumulative effect of change on prior year’s financial statements, if material, but will not require statements to be reissued. The FSP is effective for the first interim or annual period beginning after June 15, 2004.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2004, SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt and preferred trust securities. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).


	Expected Maturity Date
																						Fair
	2004			2005			2006			2007			2008			Thereafter(2)			Total			Value
Long-term Debt
SPR

Fixed Rate	$	17,550	(1)	$	—		$	—		$	240,218		$	—		$	635,000		$	892,768		$	1,097,961
Average Interest Rate		8.00	%		0.00	%		0.00	%		7.93	%		0.00	%		7.98	%		7.97	%
NPC

Fixed Rate	$	7		$	15		$	15		$	17		$	13		$	1,863,548		$	1,863,615		$	1,878,428
Average Interest Rate		8.17	%		8.17	%		8.17	%		8.17	%		8.17	%		8.00	%		8.00	%
Variable Rate																$	125,000		$	125,000		$	125,000
Average Interest Rate																	1.60	%		1.60	%
SPPC

Fixed Rate	$	1,025		$	2,400		$	52,400		$	2,400		$	322,400		$	617,850		$	998,475		$	983,770
Average Interest Rate		6.10	%		6.10	%		6.72	%		6.10	%		7.99	%		6.53	%		7.01	%

Total Debt	$	18,582		$	2,415		$	52,415		$	242,635		$	322,413		$	3,241,398		$	3,879,858		$	4,085,159

(1) SPR includes the debt of Sierra Pacific Communications of $17.6 million which is included in “Liabilities of Discontinued Operations”. See Note 12 in the Condensed Notes to Consolidated Financial Statements, Disposal of Assets.

(2) SPR’s “Thereafter” amount of $635 million includes the total amount of the 7.25% Convertible Notes due at maturity ($300 million). This differs from the carrying value of $237,974 million included in the balance sheet amount of Long-term debt, which is being accreted to face value using the effective interest method.

Commodity Price Risk

See the 2003 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2003.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $21 million as of June 30, 2004. The increase from the first quarter 2004 to the second quarter 2004 is due to the increase in the forward market for fuel and purchased power and because of new contracts entered into during the second quarter 2004. In the event that the trading counterparties are unable to deliver under their contracts, it may be necessary for the Utilities to purchase alternative energy at a higher market price.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

SPR, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of June 30, 2004, the registrants’ disclosure controls and procedures are adequate and effective to ensure that material information relating to the registrants and their consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, particularly during the period for which this quarterly report has been prepared.

(b) Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the second quarter of 2004 that have materially effected, or are reasonably likely to materially effect, internal controls over financial reporting. SPR, NPC and SPPC are currently in the process of evaluating all internal controls over financial reporting in accordance with the requirement of Section 404A of the Sarbanes-Oxley Act of 2002. Throughout the process, controls are documented and tested for effectiveness, and control deficiencies, if any, are identified and are being remediated.

PART II

ITEM 1. LEGAL PROCEEDINGS

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

On September 26, 2003, the Bankruptcy Court entered a summary judgment (the “Judgment”) in favor of Enron for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment 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. 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 NPC’s $235 million General and Refunding Mortgage Bond, Series H plus SPPC’s $103 million General and Refunding Mortgage Bond, Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which would lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made the payments as ordered on February 10, 2004. The Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall seek a ruling from the PUCN to determine whether the cash payments into escrow trigger the Utilities’ rights to seek recovery of such amounts through the Utilities’ deferred energy rate cases.

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. The FERC’s order is discussed further below. Enron has since filed a petition with the Federal District Court in New York seeking to enjoin the Utilities from proceeding with their FERC complaint. Enron contends that the issues in the Utilities complaint already have been considered in the Enron Bankruptcy court. The Federal District Court has set a hearing date of August 13 to hear oral arguments on Enron’s most recent request. The Utilities are unable to predict whether the FERC’s decision in the proceeding will affect their appeal of the Judgment or any subsequent appeals of the Judgment.

FERC 206 complaints

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

The Utilities 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 by terminating power suppliers that did not deliver power, including Enron.

On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints finding that the strict public interest standard applied to the case and that the company had failed to satisfy the burden of proof required by that standard. On July 28, 2003, the Utilities filed a petition for rehearing at the FERC requesting that the FERC either reconsider or rehear the case. On November 10, 2003, the FERC reaffirmed the June 26, 2003, decision. That decision has been appealed to the United States Court of Appeals for the Ninth Circuit. 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 the FERC has had a chance to review the complaint. The new complaint has been designated as Docket No. EL04-1-000.

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. In its order, the FERC determined, among other things, that it has jurisdiction over disputes involving interpretations of the WSPPA and that an evidentiary hearing would be required to determine whether Enron lawfully exercised its contract rights under the WSPPA to terminate its energy contracts with the Utilities. An initial decision is expected from the FERC by December 31, 2004. Enron has since filed a petition with the Federal District Court in New York seeking to enjoin the Utilities from proceeding with their FERC complaint. Enron contends that the issues in the Utilities complaint already have been considered in the Enron Bankruptcy court. The Federal District Court has set a hearing date of August 13 to hear oral arguments on Enron’s most recent request. The Utilities are unable to predict the outcome of this FERC proceeding.

On December 15, 2003, the Utilities filed an appeal in the United States Court of Appeals for the District of Columbia of a separate order issued by the FERC in its so-called Show Cause investigation into Enron trading practices. The appeal challenges two aspects of the FERC’s ruling: (1) the FERC’s refusal to revoke the market-based rate authority under which Enron sold power to the Utilities as of the date of Enron’s violations of that authority; and (2) the FERC’s decision to change the nature of the proceeding from an adjudicatory proceeding, in which the Utilities were not allowed to intervene or participate. On July 21, 2004, the FERC announced that it was revisiting its decision to revoke Enron’s market-based rate authority, and set the question for hearing. There is the possibility that the FERC would revoke Enron’s authority as of a date prior to when it entered into contracts with the Utilities, thereby voiding approximately $300 million in potential payments to Enron under those contracts. At this time we are unable to state the likelihood of a potential favorable outcome of the appeal.

Reliant Antitrust Litigation

Nevada Power Company

Morgan Stanley Proceedings

motion to intervene in the Section 206 action commenced by NPC against Enron at the FERC, and the FERC denied MSCG’s motion. On October 23, 2003, NPC filed a motion to stay the District Court proceedings, pending guidance on applicable legal principles from the FERC, which guidance may be provided in connection with a complaint NPC filed against Enron with regard to exercise of default and early termination rights. On February 2, 2004, the District Court granted NPC’s motion, and NPC’s complaint for declaratory relief before that court is now stayed until at least August 12, 2004 pending FERC guidance. On July 22, 2004, the FERC issued an order stating that it would convene a hearing regarding the NPC complaint against Enron (discussed above). At this time, NPC is unable to predict the outcome or timing of the District Court complaint.

Reliant Resources and IDACORP Energy, L.P.

El Paso Merchant Energy

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 as well as the amount remaining unpaid under the contracts for power delivered between May 2002 and October 2002. NPC claims that EPME owes NPC 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. On January 12, 2004, EPME filed a motion to dismiss the complaint on grounds of lack of personal jurisdiction and failure to state a claim for relief. On February 27, 2004, NPC filed its response to the motion to dismiss. EPME replied on March 17, 2004. In June 2004, EPME’s motion to dismiss was denied and discovery is ongoing. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Environmental Matters

Sierra Pacific Power Company

Piñon Pine

In its 2003 General Rate Case, SPPC sought recovery of all of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project. The coal gasifier represented an experimental technology that was being tested pursuant to a Department of Energy (“DOE”) Clean Coal Technology initiative. Under the terms of a cooperative agreement with the DOE, SPPC agreed to fund 50% of the costs of constructing the Piñon Pine unit, with the DOE funding the remaining 50% of the costs of the project. SPPC’s participation in the Coal Gasification Demonstration Project was permitted and constructed with PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit was never fully operational. After numerous attempts to re-engineer various components of the coal gasifier, the technology has been determined to be unworkable. In its order of May 25, 2004, the PUCN disallowed $42 million of unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada in June 2004 (CV04-01434). A briefing schedule has been established. SPPC is unable to express any opinion as to the likelihood or remoteness of any recovery from this case.

Sierra Pacific Resources and Nevada Power Company

Lawsuit Against Natural Gas Providers

On April 21, 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders. On July 3, 2003, SPR and NPC filed a First Amended Complaint. Motions to dismiss were filed by all of the defendants and were heard by the court on January 27, 2004. The motions to dismiss were granted based on a filed rate defense asserted by the defendants. SPR and NPC filed a Motion to Reconsider, which was heard by the court on April 20, 2004. The court granted the Motion to Reconsider and allowed SPR and NPC to amend the complaint. A Second Amended Complaint was filed on June 4, 2004.

The Second Amended Complaint names three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company (“El Paso”); (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company (“SoCal”), and San Diego Gas and Electric (“SDG&E”) (collectively “Sempra”). New motions to dismiss were filed by all of the defendants on July 15, 2004. These motions are currently being responded to and a hearing is scheduled for September 23, 2004.

The motions to dismiss assert the following defenses by the identified defendants: SDG&E, SoCal, and El Paso Corporation (only the parent) moved to dismiss for lack of personal jurisdiction; and all of the remaining defendants moved to dismiss on the merits, arguing primarily (a) that the Natural Gas Act and the filed rate doctrine barred all claims; (b) that SPR had no injury since it bought no gas; and (c) that there were defenses to individual legal theories (primarily based upon the lack of gas purchases by NPC from most of the defendants). It is not possible to predict with certainty the outcome of this matter.

Sierra Pacific Resources

Touch America and Sierra Touch America LLC

regarding the System, these parties have conducted negotiations which have resulted in the SPC Settlement Agreement. On July 15, 2004, TAI filed a motion with the bankruptcy court seeking approval of the SPC Settlement Agreement; the anticipated hearing date for such motion is July 28, 2004. The SPC Settlement Agreement will be a component of the debtor TAI’s Chapter 11 plan of liquidation. TAI’s disclosure statement is scheduled for an approval proceeding on August 13, 2004. While no hearing date has yet been set for Chapter 11 plan confirmation, TAI has also filed a motion to extend the exclusivity period for approval of the plan through the end of November, and such approval may occur before year-end.

Other material litigation filed against or by SPR, NPC and SPPC was described under Item 3 in their Annual Reports on Form 10-K for the year ended December 31, 2003 and Item 1 in their Quarterly Reports on Form 10-Q for the quarter ended March 31, 2004. No other material developments have occurred with respect to the litigation described in the 10-K and the 10-Q.

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

The 2004 Annual Meeting of the Stockholders of Sierra Pacific Resources was held at 10:00 a.m., Pacific Daylight Time, on Monday, May 3, 2004, at Harrah’s Hotel/Casino, 219 North Center Street, Reno, Nevada.

Three proposals were presented for stockholder consideration: (1) election of three members of the Board of Directors to serve until the Annual Meeting in 2007, and until their successors are elected and qualified; (2) approval of the renewal of the Executive Long-Term Incentive Plan; and (3) adoption of a shareholder proposal requesting Directors to submit to shareholder vote at the earliest practicable time any decision to maintain, continue, or adopt a Shareholder Rights Plan.

Three Directors, James R. Donnelly, Walter M. Higgins, and John F. O’Reilly, were elected to serve three year terms expiring at the 2007 Annual Meeting of Stockholders. Renewal of the Executive Long-Term Incentive Plan and the shareholder proposal were approved by the required affirmative vote of the stockholders. Directors whose term expires in 2005: Krestine M. Corbin, and Clyde T. Turner. Directors whose term expires in 2006: Mary Lee Coleman, T.J. Day, and Jerry E. Herbst.

The certified voting results are shown below:


Election of Directors	For		Withheld
James R. Donnelley		70,747,505		35,870,001
Walter M. Higgins		75,318,159		31,299,347
John F. O’Reilly		70,883,485		35,734,021


	For		Against		Abstain		Broker Non Vote
To approve a renewal of the Executive Long-Term Incentive Plan		54,451,463		21,938,302		8,166,114		22,061,627


	For		Against		Abstain		Broker Non Vote
To adopt a shareholder proposal requesting Directors to submit to shareholder approval at the earliest practicable time any decision to maintain, continue, or adopt a shareholder rights plan		56,490,422		20,014,629		8,050,828		22,061,627

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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


Sierra Pacific Resources

Exhibit 10.1		Stephen R. Wood Employment Letter dated June 29, 2004.

Nevada Power Company

Exhibit 4.1		Officer’s Certificate establishing the terms of Nevada Power Company’s 61/2% General and Refunding Mortgage Notes, Series I, due 2012.

Exhibit 4.2		Form of Nevada Power Company’s 61/2% General and Refunding Mortgage Notes, Series I, due 2012.

Exhibit 4.3		Registration Rights Agreement dated April 7, 2004 between Nevada Power Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Lehman Brothers Inc., as Initial Purchasers of the 61/2% General and Refunding Mortgage Notes, Series I, due 2012.

Exhibit 10.2		Credit Agreement dated May 4, 2004 among Nevada Power Company, the several banks and other financial institutions from time to time parties to the Agreement, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Lehman Brothers Inc., as joint lead arrangers and joint bookrunners, Lehman Commercial Paper Inc., as syndication agent, and Merrill Lynch Capital Corporation, as documentation agent and administrative agent.

Sierra Pacific Power Company

Exhibit 4.4		Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 61/4% General and Refunding Mortgage Notes, Series H, due 2012.

Exhibit 4.5		Form of Sierra Pacific Power Company’s 61/4% General and Refunding Mortgage Notes, Series H, due 2012.

Exhibit 4.6		Registration Rights Agreement dated April 16, 2004 between Sierra Pacific Power Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Lehman Brothers Inc., as Initial Purchasers of the 61/4% General and Refunding Mortgage Notes, Series H, due 2012.

Exhibit 10.3		Credit Agreement dated May 4, 2004 among Sierra Pacific Power Company, the several banks and other financial institutions from time to time parties to the Agreement, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Lehman Brothers Inc., as joint lead arrangers and joint bookrunners, Lehman Commercial Paper Inc., as syndication agent, and Merrill Lynch Capital Corporation, as documentation agent and administrative agent.

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

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

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

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

Exhibit 32.2		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K:

Form 8-K dated April 1, 2004, filed by SPR and SPPC – Item 5, Other Events

Disclosed that SPPC, the Staff of the Public Utilities Commission of Nevada (PUCN) and other interveners in SPPC’s 2003 general rate case negotiated a settlement agreement, subject to the approval of the PUCN, that resolves most of the issues in the revenue requirement and cost of capital portions of SPPC’s case.

Form 8-K dated April 5, 2004, filed by SPR, NPC and SPPC – Item 5, Other Events

Disclosed and included as an exhibit, SPR’s press release, dated April 5, 2004, announcing that the Bankruptcy Court of the Southern District of New York authorized an agreement reached between SPR’s two electric utilities and Enron regarding additional cash collateral to be placed into escrow pending an appeal of the court’s previous decision involving the companies’ dispute over power contracts.

Form 8-K dated May 3, 2004, filed by SPR, NPC and SPPC – Item 5, Other Events

Disclosed that at the 2004 Annual Meeting of the Stockholders of SPR held on Monday, May 3, 2004, three members were elected to the Board of Directors to serve for terms expiring in 2007. Also, approved were the Executive Long-Term Incentive Plan and the adoption of a shareholder proposal requesting Directors to submit to shareholder vote at the earliest practicable time any decision to maintain, extend, or adopt a any poison pill.

Form 8-K dated May 26, 2004, filed by SPR and SPPC – Item 5, Other Events

Disclosed that on May 26, 2004, the PUCN issued its decision on the 2003 General Rate Case filed by SPPC. In its decision the PUCN allowed $40 million of the $88 million rate increase requested by SPPC. Additionally, the PUCN issued its decision on the costs associated with the development and construction of the Piñon Pine generating facility. Of the $95 million requested, the PUCN decision allows SPPC to recover approximately $48 million of costs related to the Piñon Pine facility.

Form 8-K dated June 8, 2004, filed by SPR, NPC and SPPC – Item 5, Other Events

Disclosed that on June 8, 2004, NPC and SPPC entered into an agreement with Enron Power Marketing, Inc. (“EPMI”), which agreement was approved and “so ordered” by the U.S. Bankruptcy Court, regarding NPC’s and SPPC’s (collectively, the “Utilities”) appeal of the September 26, 2003 judgment against the Utilities for alleged damages related to EPMI’s termination of its power supply agreements with the Utilities.

Form 8-K dated June 8, 2004, filed by SPR and SPPC – Item 5, Other Events

Disclosed that on June 8, 2004, SPPC petitioned the Second Judicial Court of the State of Nevada in and for the County of Washoe for judicial review of portions of the PUCN’s final order in SPPC’s 2003 General Rate Case.

Form 8-K dated June 23, 2004, filed by SPR and NPC – Item 5, Other Events

Disclosed that on June 23, 2004, NPC reached an agreement to acquire from Duke Energy the partially constructed 1,200 MW (megawatt) natural gas-fired combined-cycle power plant located in the Moapa Valley, northeast of Las Vegas. The transaction, which is subject to approval by the Public Utilities Commission of Nevada (PUCN), is expected to close this fall.


PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements (Unaudited)
Sierra Pacific Resources -
Consolidated Balance Sheets — June 30, 2004 and December 31, 2003			3
Consolidated Statements of Operations — Three Months and Six Months Ended June 30, 2004 and 2003			4
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2004 and 2003			5
Nevada Power Company -
Consolidated Balance Sheets — June 30, 2004 and December 31, 2003			6
Consolidated Statements of Operations — Three Months and Six Months Ended June 30, 2004 and 2003			7
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2004 and 2003			8
Sierra Pacific Power Company -
Consolidated Balance Sheets — June 30, 2004 and December 31, 2003			9
Consolidated Statements of Operations — Three Months and Six Months Ended June 30, 2004 and 2003			10
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2004 and 2003			11
Condensed Notes to Consolidated Financial Statements			12
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			43
Sierra Pacific Resources			51
Nevada Power Company			58
Sierra Pacific Power Company			66
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk			81
ITEM 4. Controls and Procedures			82
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings			82
ITEM 4. Submission of Matters to a Vote of Security Holders			87
ITEM 5. Other Information			87
ITEM 6. Exhibits and Reports on Form 8-K			88
Signature Page and Certifications			90

	(1)		Balance approved for collection on July 7, 2004.

	(2)		Amounts related to claims for terminated supply contracts are discussed in Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies.

	•		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 have sufficient liquidity and the ability under certain restrictions to provide dividends to SPR;

	•		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; and

	•		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.

	•		A Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.03%, an improvement over NPC’s previous ROE and ROR, which were 10.1% and 8.37%, respectively. NPC had requested an ROE of 12.4% and ROR of 10.0%;

	•		Approximately $7 million of the $8.8 million of goodwill and merger costs requested to be recovered annually over each of the next two years;

	•		Approximately $21.4 million of generation divestiture costs to be recovered over an extended period of 8 years;

	•		Approved the establishment of a regulatory asset account to capture costs related to the shutdown of the Mohave Power Plant.

	1st:		NPC expects to finance the acquisition with a $250 million revolving credit facility that will be put in place contingent upon closing the transaction. This revolving credit facility will fund the $182 million acquisition price as well as some of the initial construction expenditures.

	2nd:		Before the end of the year or early next year, NPC expects to go to market with an offering for long-term financing of approximately $250 million. The proceeds from this financing will be used to pay down the revolver.

	•		SPPC is allowed to recover a $40 million increase in annual rates.

	•		SPPC is allowed a Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.26%, an improvement over SPPC’s previous ROE and ROR, which were 10.17% and 8.61%, respectively. SPPC had sought an ROE of 12.4% and ROR of 10.03%.

	•		The agreement accepted SPPC’s requested accounting treatment as filed in its application for purposes of recording revenues, expenses and assets with the following exception. Accounting issues common to SPPC’s general rate case and NPC’s general rate case that was decided by the PUCN on March 26, 2004, in Docket No. 03-10001, are treated as set forth in the PUCN’s Order on NPC’s general rate case, except for merger costs. The accounting treatment for merger costs and goodwill established in the NPC decision will apply to the recovery of these costs by SPPC, except that SPPC will include in rates 100% of the costs as filed until recovery is reset by the PUCN in SPPC’s next general rate application.

	(1)		SPR Holding Co. and Other Subs. includes the debt of Sierra Pacific Communications of $17.6 million which is included in “Liabilities of Discontinued Operations”. See Note 12 in the Condensed Notes to Consolidated Financial Statements, Disposal of Assets.

	(2)		SPR’s “Thereafter” amount of $635 million includes the total amount of the 7.25% Convertible Notes due at maturity ($300 million). This differs from the carrying value of $237,974 million included in the balance sheet amount of Long-term debt, which is being accreted to face value using the effective interest method.

	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 permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC’s obligations with respect to energy suppliers, or

	3.		in the case of the Series I Notes and Series G Notes and the Series H Bond, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan.

	1.		at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’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 Series H Notes, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, or

	3.		indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Integrated Resource Plan.

	1.		at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or

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

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

	•		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

	•		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, NPC’s General and Refunding Mortgage Bond, Series H, which was issued December 4, 2003, NPC’s 61/2% General and Refunding Mortgage Notes, Series I, due 2012, which were issued on April 7, 2004, and NPC’s Revolving Credit Agreement, which was established on May 4, 2004, limit the amount of payments in respect of common stock that NPC may make 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

	•		under the Series E Notes, $15 million from the date of the issuance of the Series E Notes, and

	•		under the Series G, Series I Notes and the Series H Bond, and the Revolving Credit Agreement, $25 million from the date of the issuance of the Series G, Series I Notes and the Series H Bond and the establishment of the Revolving Credit Agreement, respectively.

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

	•		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 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, the Bond or Credit Facility, 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, Series I 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.

	•		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.

	•		those payments do not exceed $50 million for any one calendar year,

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

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

			million from the date of the issuance of the Series H Notes, the establishment of the Revolving Credit Agreement and issuance of the Series E Bond, respectively.

			In addition, SPPC 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 H Notes, the Revolving Credit Agreement, or the Series E Bond,

	•		SPPC has a ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2 to 1, and

	•		the total amount of such dividends is less than:

	•		the sum of 50% of SPPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series H Notes, the establishment of the Revolving Credit Agreement or the issuance of the Series E Bond, plus

	•		100% of SPPC’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 SPPC, plus

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

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

			If SPPC’s Series H Notes or the Series E 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 Bond remain investment grade.

	•		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 March 31, 2004, the PUCN issued an order in connection with its authorization of the issuance of long-term debt securities by NPC. On April 8, 2004, the PUCN issued an order in connection with its authorization of the issuance of long-term debt securities by SPPC. These PUCN orders, for NPC Docket 04-1014 and SPPC Docket 03-12030, permit NPC and SPPC to annually dividend an aggregate of either SPR’s actual cash requirements for debt service, or $70 million, whichever is less. These orders, in conjunction with earlier orders on this issue, also provide that the dividend limitation may be reviewed in a subsequent application to grant short-term debt authority and that, in the event that circumstances change 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 circumstances, 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

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

	(2)		unfavorable rulings in rate cases filed and to be filed by NPC and SPPC (collectively, the “Utilities”) with the Public Utilities Commission of Nevada (the “PUCN”), including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas recorded by SPPC for its gas distribution business;

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

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

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

	(6)		whether NPC will receive PUCN approval to purchase a partially constructed 1,200 MW combined-cycle power plant from Duke Energy and to finance the purchase and construction of the power plant;

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

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

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

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

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

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

	(13)		whether the Utilities will be successful in obtaining PUCN approval to recover the outstanding balance of their goodwill and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

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

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

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

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

	(18)		the loss of any significant customers;

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

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

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

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

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

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

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

	•		Results of Operations

	•		Analysis of Cash Flows

	•		Liquidity and Capital Resources

	•		Regulatory Proceedings (Utilities)

	•		Recent Pronouncements

	•		In March 2004, SPR successfully repurchased approximately $174 million of its 8.3/4% Notes due 2005 through the issuance and sale of $335 million 8.625% Senior Notes due 2014. The balance of the net proceeds from the $335 million issuance were used in May of 2004 to legally extinguish the approximately $126 million of remaining principal amount of SPR’s 83/4% Notes which were not tendered, and to pay associated interest and to the payment of fees and expenses associated with the tender offer.

	•		In April 2004, NPC refinanced $130 million of its 6.2% long-term debt that matured in April 2004 through the issuance and sale of its $100 million 6.5% Series I General and Refunding Mortgage Notes that will mature in April 2012.

	•		In April 2004, SPPC refinanced $99 million of its 10.5% term loan that was to mature in October 2005 through the issuance and sale of its 6.25% Series H General and Refunding Mortgage Notes that will mature in April 2012.

	•		In May 2004, SPPC remarketed $80 million of Water Facilities Refunding Revenue Bonds that were subject to mandatory repurchase on May 3, 2004 and adjusted the rate on the bonds from their prior one-year rate of 7.50% to a 5.0% rate in effect through July 1, 2009.

	•		To support the Utilities power and natural gas purchase requirements at the onset of the summer 2004 season and for other general corporate and working capital purposes, NPC and SPPC replaced their receivables purchase facility with revolving credit facilities. The revolving credit facilities offer the Utilities additional liquidity at more favorable rates than their receivables purchase facilities.

	•		an unrealized loss of approximately $123.5 million on the derivative instrument associated with the issuance of $300 million of convertible debt recorded in the second quarter of 2003;

	•		the write-off of disallowed deferred energy costs (excluding carrying charges) of approximately $46 million and $45 million by NPC and SPPC, respectively, recorded in the second quarter of 2003; and

	•		losses by SPR subsidiaries due to the recognition of asset impairments of $32.9 million for SPC recorded in the second quarter of 2003, now reported in Discontinued Operations.

			Partially offsetting the improved operating results during 2004 were the following charges:

	•		a charge of approximately $9.8 million during the second quarter of 2004 of interest expense costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes due 2005. (See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt); and

	•		a charge of approximately $47 million recorded during the second quarter of 2004 as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Piñon Pine. (See Regulatory Proceedings (Utilities)).

	•		an unrealized loss of approximately $107.6 million on the derivative instrument associated with the issuance of $300 million of convertible debt recorded in 2003;

	•		the write-off of disallowed deferred energy costs (excluding carrying charges) of approximately $46 million and $45 million by NPC and SPPC, respectively, recorded in 2003; and

	•		losses by SPR subsidiaries due to the recognition of asset impairments of $32.9 million for SPC recorded in 2003.

			Partially offsetting the improved operating results during 2004 were the following charges:

	•		a non-cash goodwill impairment charge of approximately $11.7 million during 2004 (See Note 11 of the Condensed Notes to Consolidated Financial Statements, Goodwill);

	•		a non-cash charge in 2004 to write-off disallowed merger costs of approximately $5.9 million;

	•		a charge of approximately $23.7 million during 2004 of tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8 3/4% Senior Unsecured Notes due 2005. (See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt); and

	•		a charge of approximately $47 million as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Piñon Pine. (See Regulatory Proceedings (Utilities)).