Nv Energy 10Q 2004 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

		OR

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

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

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

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

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. Yesx 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 Yesx No o;Nevada Power Company Yes o No x ; Sierra Pacific Power Company Yeso 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 Common Stock, $1.00 par value of Sierra Pacific Resources		Outstanding at November 8, 2004 117,430,679 Shares

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

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

SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2004

CONTENTS


PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements (Unaudited)
Sierra Pacific Resources -
Consolidated Balance Sheets – September 30, 2004 and December 31, 2003			3
Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2004 and 2003			4
Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2004 and 2003			5
Nevada Power Company -
Consolidated Balance Sheets –September 30, 2004 and December 31, 2003			6
Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2004 and 2003			7
Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2004 and 2003			8
Sierra Pacific Power Company -
Consolidated Balance Sheets – September 30, 2004 and December 31, 2003			9
Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2004 and 2003			10
Consolidated Statements of Cash Flows – Nine Months Ended September 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			50
Sierra Pacific Resources			59
Nevada Power Company			67
Sierra Pacific Power Company			76
ITEM 3.Quantitative and Qualitative Disclosures about Market Risk			96
ITEM 4.Controls and Procedures			96
PART II - OTHER INFORMATION
ITEM 1.Legal Proceedings			97
ITEM 4.Submission of Matters to a Vote of Security Holders			102
ITEM 5.Other Information			102
ITEM 6.Exhibits			102
Signature Page and Certifications			104
EX-10.1 PURCHASE AGREEMENT
EX-10.2 CLOSING AGREEMENT
EX-10.3 ENGINEERING,PROCUREMENT AND CONSTRUCTION AGREEMENT
EX-10.4 EXHIBIT A SPECIFICATION
EX-10.5 AMENDED AND RESTATED CREDIT AGREEMENT
EX-10.6 CREDIT AGREEMENT
EX-31.1 SECTION 302 CERTIFICATION OF CEO
EX-31.2 SECTION 302 CERTIFICATION OF CFO
EX-32.1 SECTION 906 CERTIFICATION OF CEO
EX-32.2 SECTION 906 CERTIFICATION OF CFO

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	September 30,		December 31,
	2004		2003
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,530,179	$	6,353,399
Less accumulated provision for depreciation		2,046,875		1,953,271

		4,483,304		4,400,128
Construction work-in-progress		153,823		242,522

		4,637,127		4,642,650

Investments and other property, net		70,367		73,130

Current Assets:
Cash and cash equivalents		153,762		181,757
Restricted cash and investments (Note 1)		88,125		54,705
Accounts receivable less allowance for uncollectible accounts: 2004-$41,612; 2003-$44,917		388,402		301,322
Deferred energy costs - electric (Note 1)		82,906		295,677
Deferred energy costs - gas (Note 1)		1,136		1,358
Materials, supplies and fuel, at average cost		73,808		79,525
Risk management assets		36,119		22,099
Accumulated deferred income tax		43,417		—
Deposits and prepayments for energy		66,489		63,847
Other		34,741		33,016

		968,905		1,033,306

Deferred Charges and Other Assets:
Goodwill (Note 11)		22,877		309,971
Deferred energy costs - electric		635,296		497,905
Regulatory tax asset		312,988		155,547
Other regulatory assets (Note 1)		487,127		142,507
Risk management assets		367		—
Risk management regulatory assets - net (Note 8)		—		14,283
Unamortized debt issuance expense		61,328		50,842
Other		117,138		103,545

		1,637,121		1,274,600

Assets of Discontinued Operations (Note 12)		30,178		40,072

	$	7,343,698	$	7,063,758

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	1,438,149	$	1,435,394
Preferred stock		50,000		50,000
Long-term debt		3,828,885		3,579,674

		5,317,034		5,065,068

Current Liabilities:
Short-term borrowings		—		25,000
Current maturities of long-term debt		8,192		218,970
Accounts payable		183,850		165,936
Accrued interest		81,271		59,592
Dividends declared		1,046		968
Accrued salaries and benefits		26,421		24,444
Deferred taxes		—		106,478
Risk management liabilities (Note 8)		3,205		16,540
Accrued income taxes		5,582		8,077
Contract termination liabilities (Note 9)		342,013		338,704
Other current liabilities		32,239		29,088

		683,819		993,797

Commitments and Contingencies (Note 9)
Deferred Credits and Other Liabilities:
Deferred federal income taxes		617,727		298,457
Deferred investment tax credit		42,880		45,329
Regulatory tax liability		39,385		41,877
Customer advances for construction		139,582		126,506
Accrued retirement benefits		107,681		112,075
Risk management regulatory liability - net (Note 8)		14,677		—
Contract termination liabilities (Note 9)		36,521		45,766
Regulatory liabilities (Note 1)		225,971		218,158
Other		89,971		80,859

		1,314,395		969,027

Liabilities of Discontinued Operations (Note 12)		28,450		35,866

	$	7,343,698	$	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						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
				As Revised (Note 1)						As Revised (Note 1)
OPERATING REVENUES:
Electric	$	887,224		$	890,137		$	2,067,948		$	2,057,781
Gas		16,387			13,931			97,742			114,421
Other		304			279			3,762			908

		903,915			904,347			2,169,452			2,173,110

OPERATING EXPENSES:
Operation:
Purchased power		392,771			458,406			849,906			946,147
Fuel for power generation		126,710			157,865			343,598			353,044
Gas purchased for resale		11,322			7,133			73,721			77,332
Deferred energy costs disallowed		—			—			1,586			90,964
Deferral of energy costs - electric - net		6,227			(58,141	)		93,058			44,729
Deferral of energy costs - gas - net		297			2,200			266			14,023
Impairment of goodwill		—			—			11,695			—
Other		80,912			73,098			244,163			230,887
Maintenance		16,046			13,972			63,150			54,799
Depreciation and amortization		51,435			49,315			153,501			141,663
Taxes:
Income tax expense/(benefit)		45,193			24,262			17,296			(32,342	)
Other than income		10,734			11,090			34,424			33,701

		741,647			739,200			1,886,364			1,954,947

OPERATING INCOME		162,268			165,147			283,088			218,163
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		717			1,039			3,282			3,883
Interest accrued on deferred energy		6,777			6,684			19,307			21,142
Disallowed merger costs		—			—			(5,890	)		—
Disallowed plant costs		—			—			(47,092	)		—
Other income		8,214			6,916			25,258			20,127
Other expense		(3,990	)		(3,751	)		(10,220	)		(10,750	)
Income (taxes) / benefit		(3,406	)		(3,090	)		7,392			(9,167	)
Unrealized gain/(loss) on derivative instrument		—			61,513			—			(46,065	)

		8,312			69,311			(7,963	)		(20,830	)

Total Income Before Interest Charges		170,580			234,458			275,125			197,333
INTEREST CHARGES:
Long-term debt		74,517			75,140			235,696			217,816
Other		5,437			50,821			36,385			70,525
Allowance for borrowed funds used during construction		(1,123	)		(1,481	)		(4,963	)		(4,368	)

		78,831			124,480			267,118			283,973

INCOME (LOSS) FROM CONTINUING OPERATIONS		91,749			109,978			8,007			(86,640	)
DISCONTINUED OPERATIONS:
Loss from discontinued operations (net of income taxes of $163, $603, $2,091 and $16,642 respectively)		(127	)		(1,231	)		(3,769	)		(31,133	)

NET INCOME/(LOSS)		91,622			108,747			4,238			(117,773	)
Preferred stock dividend requirements of subsidiary		975			975			2,925			2,925

INCOME/(LOSS) APPLICABLE TO COMMON STOCK	$	90,647		$	107,772		$	1,313		$	(120,698	)

Amount per share (Note 10)
Income/(loss) from continuing operations – basic	$	0.50		$	0.60		$	0.04		$	(0.75	)
Income/(loss) applicable to common stock – basic	$	0.50		$	0.59		$	0.01		$	(1.05	)
Income/(loss) from continuing operations – diluted	$	0.50		$	0.29		$	0.04		$	(0.75	)
Income/(loss) applicable to common stock – diluted	$	0.50		$	0.28		$	0.01		$	(1.05	)
Weighted Average Shares of Common Stock - basic		183,117,111			182,926,433			183,045,191			115,294,693

Weighted Average Shares of Common Stock - diluted		183,117,111			183,014,871			183,045,191			115,294,693

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Nine Months Ended
	September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	4,238		$	(117,773	)
Non-cash items included in net income (loss):
Depreciation and amortization		153,501			141,663
Deferred taxes and deferred investment tax credit		7,113			(53,506	)
AFUDC and capitalized interest		(8,245	)		(8,251	)
Amortization of deferred energy costs - electric		206,784			191,196
Amortization of deferred energy costs - gas		3,126			10,784
Deferred energy costs disallowed		1,586			90,965
Goodwill impairment		11,695			—
Unrealized loss on derivative instrument		—			46,065
Impairment of assets of subsidiary		—			32,911
Loss on disposal of discontinued operations		2,346			9,309
Plant costs disallowed		47,092			—
Other non-cash		(37,109	)		(14,098	)
Changes in certain assets and liabilities:
Accounts receivable		(87,080	)		(36,934	)
Deferral of energy costs - electric		(132,991	)		(151,435	)
Deferral of energy costs - gas		(2,905	)		2,815
Materials, supplies and fuel		5,716			8,611
Other current assets		(4,369	)		37,424
Accounts payable		17,914			(54,235	)
Escrow payment for terminating supplier		(60,867	)		—
Other current liabilities		24,192			51,591
Change in net assets of discontinued operations		131			(12,072	)
Other assets		(10,491	)		11,478
Other liabilities		8,952			74,365

Net Cash from Operating Activities		150,329			260,873

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(264,234	)		(276,438	)
AFUDC and other charges to utility plant		8,245			8,251
Customer advances for construction		13,076			10,758
Contributions in aid of construction		16,973			9,656

Net cash used for utility plant		(225,940	)		(247,773	)
Investments in subsidiaries and other property - net		8,227			(7,634	)

Net Cash used by Investing Activities		(217,713	)		(255,407	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Increase /(Decrease) in short-term borrowings		(25,000	)		—
Change in restricted cash and investments		27,448			(104,115	)
Proceeds from issuance of long-term debt		565,000			650,842
Retirement of long-term debt		(526,568	)		(549,358	)
Sale of common stock, net of issuance cost		1,356			(981	)
Dividends paid		(2,847	)		(2,549	)

Net Cash from Financing Activities		39,389			(6,161	)

Net Decrease in Cash and Cash Equivalents		(27,995	)		(695	)
Beginning Balance in Cash and Cash Equivalents		181,757			192,064

Ending Balance in Cash and Cash Equivalents	$	153,762		$	191,369

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	247,070		$	188,482
Income taxes	$	—		$	(1,521	)
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

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

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	September 30,		December 31,
	2004		2003
ASSETS
Utility Plant at Original Cost:
Plant in service	$	3,984,687	$	3,816,630
Less accumulated provision for depreciation		1,091,812		1,018,044

		2,892,875		2,798,586
Construction work-in-progress		96,258		109,148

		2,989,133		2,907,734

Investments and other property, net		36,140		36,312

Current Assets:
Cash and cash equivalents		108,265		144,897
Restricted cash (Note 1)		50,049		2,600
Accounts receivable less allowance for uncollectible accounts: 2004-$36,337; 2003-$40,297		264,170		167,296
Accounts receivable, affiliate companies		2,728		3,533
Deferred energy costs - electric (Note 1)		58,205		247,249
Materials, supplies and fuel, at average cost		42,881		41,076
Risk management assets (Note 8)		14,126		11,702
Accumulated deferred income tax		—		—
Deposits and prepayments for energy		44,504		39,794
Other		22,802		21,540

		607,730		679,687

Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		482,476		371,305
Regulatory tax asset		199,539		102,282
Other regulatory assets (Note 1)		275,962		60,721
Risk management regulatory assets - net (Note 8)		—		3,109
Unamortized debt issuance expense		37,121		34,052
Other		31,538		15,557

		1,026,636		587,026

	$	4,659,639	$	4,210,759

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,417,041	$	1,174,645
Long-term debt		2,024,991		1,899,709

		3,442,032		3,074,354

Current Liabilities:
Current maturities of long-term debt		5,965		135,570
Accounts payable		133,461		107,812
Accrued interest		49,815		35,399
Dividends declared		399		—
Accrued salaries and benefits		11,871		10,315
Deferred taxes		662		97,464
Risk management liabilities (Note 8)		1,471		5,266
Accrued income taxes		2,555		4,934
Contract termination liabilities (Note 9)		238,152		235,729
Other current liabilities		25,984		22,397

		470,335		654,886

Commitments and Contingencies (Note 9)
Deferred Credits and Other Liabilities:
Deferred federal income taxes		369,717		124,914
Deferred investment tax credit		19,049		20,272
Regulatory tax liability		14,799		15,776
Customer advances for construction		78,602		71,176
Accrued retirement benefits		18,829		5,825
Risk management regulatory liability - net (Note 8)		4,331		—
Contract termination liabilities (Note 9)		34,629		43,916
Regulatory liabilities (Note 1)		145,572		147,887
Other		61,744		51,753

		747,272		481,519

	$	4,659,639	$	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						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
OPERATING REVENUES:
Electric	$	633,609		$	639,661		$	1,410,067		$	1,396,825
OPERATING EXPENSES:
Operation:
Purchased power		300,290			333,069			619,329			657,455
Fuel for power generation		67,216			95,453			176,883			209,900
Deferred energy costs disallowed		—			—			1,586			45,964
Deferral of energy costs-net		9,496			(35,967	)		91,622			48,260
Other		45,515			44,749			136,150			136,964
Maintenance		10,834			9,203			47,580			38,390
Depreciation and amortization		29,900			28,474			88,630			81,095
Taxes:
Income tax expense		43,346			30,556			37,232			3,734
Other than income		6,170			6,387			19,743			19,429

		512,767			511,924			1,218,755			1,241,191

OPERATING INCOME		120,842			127,737			191,312			155,634
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		487			281			1,769			1,922
Interest accrued on deferred energy		5,142			5,952			15,335			16,896
Disallowed merger costs		—			—			(3,961	)		—
Other income		5,335			4,042			16,464			11,633
Other expense		(1,698	)		(1,441	)		(4,626	)		(4,491	)
Income taxes		(3,109	)		(3,084	)		(8,154	)		(8,277	)

		6,157			5,750			16,827			17,683

Total Income Before Interest Charges		126,999			133,487			208,139			173,317
INTEREST CHARGES:
Long-term debt		37,736			37,365			112,570			104,215
Other		3,824			34,171			13,652			46,165
Allowance for borrowed funds used during construction		(759	)		(573	)		(2,465	)		(2,149	)

		40,801			70,963			123,757			148,231

NET INCOME	$	86,198		$	62,524		$	84,382		$	25,086

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Nine Months Ended
	September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	84,382		$	25,086
Non-cash items included in net income:
Depreciation and amortization		88,630			81,095
Deferred taxes and deferred investment tax credit		48,544			12,009
AFUDC		(4,234	)		(4,071	)
Amortization of deferred energy costs		178,451			156,065
Deferred energy costs disallowed		1,586			45,964
Other non-cash		(23,730	)		(13,915	)
Changes in certain assets and liabilities:
Accounts receivable		(96,070	)		(73,859	)
Deferral of energy costs		(102,163	)		(124,701	)
Materials, supplies and fuel		(1,805	)		2,188
Other current assets		(5,974	)		(14,098	)
Accounts payable		25,649			(24,354	)
Escrow payment for terminating suppliers		(50,049	)		—
Other current liabilities		17,181			24,010
Other assets		(9,701	)		8,208
Other liabilities		14,355			70,436

Net Cash from Operating Activities		165,052			170,063

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(178,001	)		(169,986	)
AFUDC and other charges to utility plant		4,234			4,071
Customer advances for construction		7,426			7,632
Contributions in aid of construction		6,127			2,941

Net cash used for utility plant		(160,214	)		(155,342	)
Investments in subsidiaries and other property — net		(177	)		(12,758	)

Net Cash used by Investing Activities		(160,391	)		(168,100	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		2,600			3,850
Proceeds from issuance of long-term debt		130,000			350,000
Retirement of long-term debt		(134,323	)		(353,573	)
Dividends paid		(39,570	)		—

Net Cash from Financing Activities		(41,293	)		277

Net Increase (Decrease) in Cash and Cash Equivalents		(36,632	)		2,240
Beginning Balance in Cash and Cash Equivalents		144,897			95,009

Ending Balance in Cash and Cash Equivalents	$	108,265		$	97,249

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	109,401		$	96,903
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)


	September 30,		December 31,
	2004		2003
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,545,492	$	2,536,769
Less accumulated provision for depreciation		955,063		935,227

		1,590,429		1,601,542
Construction work-in-progress		57,565		133,374

		1,647,994		1,734,916

Investments and other property, net		881		916

Current Assets:
Cash and cash equivalents		34,721		20,859
Restricted cash (Note 1)		16,464		8,776
Accounts receivable less allowance for uncollectible accounts:
2004-$5,275; 2003-$4,620		122,631		133,595
Accounts receivable, affiliated companies		55,317		56,349
Deferred energy costs - electric (Note 1)		24,701		48,428
Deferred energy costs - gas (Note 1)		1,136		1,358
Materials, supplies and fuel, at average cost		30,949		38,449
Risk management assets (Note 8)		21,993		10,397
Accumulated deferred income tax		14,956		—
Deposits and prepayments for energy		21,985		24,053
Other		8,385		7,265

		353,238		349,529

Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		152,820		126,600
Regulatory tax asset		113,449		53,265
Other regulatory assets (Note 1)		211,165		62,716
Risk management assets (Note 8)		367		—
Risk management regulatory assets - net (Note 8)		—		11,174
Unamortized debt issuance expense		14,028		12,383
Other		8,787		10,970

		500,616		277,108

	$	2,502,729	$	2,362,469

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	684,580	$	593,771
Preferred stock		50,000		50,000
Long-term debt		994,984		912,800

		1,729,564		1,556,571

Current Liabilities:
Short-term borrowings		—		25,000
Current maturities of long-term debt		2,227		83,400
Accounts payable		31,526		40,731
Accrued interest		24,841		10,374
Dividends declared		968		968
Accrued salaries and benefits		12,872		11,775
Deferred taxes		—		25,726
Risk management liabilities (Note 8)		1,734		11,274
Accrued income taxes		2,906		3,009
Contract termination liabilities (Note 9)		103,861		102,975
Other current liabilities		5,504		4,120

		186,439		319,352

Commitments and Contingencies (Note 9)
Deferred Credits and Other Liabilities:
Deferred federal income taxes		325,992		231,274
Deferred investment tax credit		23,831		25,057
Regulatory tax liability		24,586		26,101
Customer advances for construction		60,980		55,330
Accrued retirement benefits		36,984		52,709
Risk management regulatory liability - net (Note 8)		10,346		—
Contract termination liabilities (Note 9)		1,892		1,850
Regulatory liabilities (Note 1)		80,399		70,271
Other		21,716		23,954

		586,726		486,546

	$	2,502,729	$	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						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
OPERATING REVENUES:
Electric	$	253,615		$	250,476		$	657,881		$	660,956
Gas		16,387			13,931			97,742			114,421

		270,002			264,407			755,623			775,377

OPERATING EXPENSES:
Operation:
Purchased power		92,481			125,337			230,577			288,692
Fuel for power generation		59,494			62,412			166,715			143,144
Gas purchased for resale		11,322			7,133			73,721			77,332
Deferred energy costs disallowed		—			—			—			45,000
Deferral of energy costs - electric - net		(3,269	)		(22,174	)		1,436			(3,531	)
Deferral of energy costs - gas - net		297			2,200			266			14,023
Other		29,899			26,684			93,601			87,522
Maintenance		5,212			4,769			15,570			16,409
Depreciation and amortization		21,530			20,811			64,866			60,478
Taxes:
Income taxes/(benefit)		9,424			(21	)		9,729			(16,229	)
Other than income		4,557			4,668			14,553			14,179

		230,947			231,819			671,034			727,019

OPERATING INCOME		39,055			32,588			84,589			48,358
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		230			758			1,513			1,961
Interest accrued on deferred energy		1,635			732			3,972			4,246
Disallowed merger costs		—			—			(1,929	)		—
Plant costs disallowed		—			—			(47,092	)		—
Other income		765			1,450			2,521			3,550
Other expense		(1,568	)		(1,450	)		(4,123	)		(5,057	)
Income (taxes)/benefit		(458	)		(454	)		14,900			(1,233	)

		604			1,036			(30,238	)		3,467

Total Income Before Interest Charges		39,659			33,624			54,351			51,825
INTEREST CHARGES:
Long-term debt		17,307			19,174			54,022			56,914
Other		928			15,675			5,555			21,404
Allowance for borrowed funds used during construction and capitalized interest		(364	)		(908	)		(2,498	)		(2,219	)

		17,871			33,941			57,079			76,099

NET INCOME/(LOSS )		21,788			(317	)		(2,728	)		(24,274	)
Preferred Dividend Requirements		975			975			2,925			2,925

Income/(Loss) applicable to common stock	$	20,813		$	(1,292	)	$	(5,653	)	$	(27,199	)

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Nine Months Ended
	September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(2,728	)	$	(24,274	)
Non-cash items included in net loss:
Depreciation and amortization		64,866			60,478
Deferred taxes and deferred investment tax credit		(8,890	)		(42,268	)
AFUDC		(4,011	)		(4,180	)
Amortization of deferred energy costs - electric		28,335			35,131
Amortization of deferred energy costs - gas		3,126			10,784
Deferred energy costs disallowed		—			45,000
Plant costs disallowed		47,092			—
Other non-cash		(2,108	)		(84	)
Changes in certain assets and liabilities:
Accounts receivable		11,996			37,205
Deferral of energy costs - electric		(30,828	)		(26,734	)
Deferral of energy costs - gas		(2,905	)		2,815
Materials, supplies and fuel		7,500			6,124
Other current assets		948			(3,574	)
Accounts payable		(9,205	)		(27,489	)
Escrow payment for terminating suppliers		(10,818	)		—
Other current liabilities		16,846			11,300
Other assets		(790	)		3,284
Other liabilities		(5,090	)		4,999

Net Cash from Operating Activities		103,336			88,517

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(86,233	)		(106,452	)
AFUDC and other charges to utility plant		4,011			4,180
Customer advances for construction		5,650			3,126
Contributions in aid of construction		10,846			6,714

Net cash used for utility plant		(65,726	)		(92,432	)
Disposal of subsidiaries and other property - net		36			(55	)

Net Cash used by Investing Activities		(65,690	)		(92,487	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings		(25,000	)		—
Change in restricted cash and investments		3,130			2,979
Proceeds from issuance of long-term debt		100,000			—
Retirement of long-term debt		(98,989	)		(1,491	)
Dividends paid		(2,925	)		(2,925	)

Net Cash used by Financing Activities		(23,784	)		(1,437	)

Net Increase (Decrease) in Cash and Cash Equivalents		13,862			(5,407	)
Beginning Balance in Cash and Cash Equivalents		20,859			88,910

Ending Balance in Cash and Cash Equivalents	$	34,721		$	83,503

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	44,183		$	50,100
Income taxes	$	—		$	(1,521	)
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 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 nine months ended September 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 benefit 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 September 30, 2003 information presented herein has been restated from the amounts reported in SPR’s interim financial statements for three and nine months ended September 30, 2003 to remove $21.5 million and $(16.1) million, respectively, of deferred tax expense/(benefit) associated with the change in the fair value of the option for the three and nine months ended September 30, 2003 and has removed $0.6 million and $1.5 million, respectively, of current tax benefit 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 three and nine months ended September 30, 2003 differ from the amounts currently reported due to revisions to reflect the discontinued operations presentation of SPC. See Note 12 – Disposal of Assets.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Amounts for the three months and nine months ended were revised as shown in the table below (dollars in thousands except per share amounts):


	Three Months Ended September 30, 2003
				Adjustment for						Adjustment for
	As Originally			Convertible			Adjustment for			Change in Accounting			Revised
	Reported			Notes			Disc. Ops SPC			Principal(1)			Balance
Operating Revenues	$	904,877		$	—		$	(530	)	$	—	$	904,347
Operating Income (loss)	$	165,444		$	(624	)	$	327		$	—	$	165,147
Income from continuing operations	$	88,301		$	20,905		$	772		$	—	$	109,978
Loss from discontinued operations	$	(459	)	$	—		$	(772	)	$	—	$	(1,231	)
Earnings applicable to common stock	$	86,867		$	20,905		$	—		$	—	$	107,772
Earnings (loss) per share—Basic:
From continuing operations	$	0.29		$	—		$	—		$	0.31	$	0.60
From discontinued operations	$	—		$	—		$	—		$	—	$	—
Earnings applicable to common stock	$	0.28		$	—		$	—		$	0.31	$	0.31
Earnings (loss) per share—Diluted:
From continuing operations	$	0.29		$	—		$	—		$	—	$	0.29
From discontinued operations	$	—		$	—		$	—		$	—	$	(0.01	)
Earnings applicable to common stock	$	0.28		$	—		$	—		$	—	$	0.28


	Nine Months Ended September 30, 2003
				Adjustment for
	As Originally			Convertible			Adjustment for
	Reported			Notes			Disc. Ops SPC			Revised Balance
Operating Revenues	$	2,174,313		$	—		$	(1,203	)	$	2,173,110
Operating Income (loss)	$	197,342		$	(1,524	)	$	22,345		$	218,163
Income (loss) from continuing operations	$	(92,872	)	$	(17,647	)	$	23,879		$	(86,640	)
Loss from discontinued operations	$	(7,254	)	$	—		$	(23,879	)	$	(31,133	)
Earnings (loss) applicable to common stock	$	(103,051	)	$	(17,647	)	$	—		$	(120,698	)
Earnings (loss) per share—Basic and Diluted:
From continuing operations	$	(0.81	)	$	(0.15	)	$	0.21		$	(0.75	)
From discontinued operations	$	(0.06	)	$	—		$	(0.21	)	$	(0.27	)
Earnings (loss) applicable to common stock	$	(0.89	)	$	(0.15	)	$	—		$	(1.05	)

(1)

For purposes of computing earnings per share, income from continuing operations and earnings applicable to common stock for the three months ended September 30, 2003, were increased for interest expense of $3.5 million, net of tax, and accretion expense of $1.8 million and decreased for unrealized gain on the derivative of $61.5 million in 2003. Subsequent to the ratification of EITF 03-6 in March 2004, this adjustment was eliminated from the calculation of basic earnings per share. See Note 10 of the Condensed Notes to Consolidated Financial Statements, Earnings Per Share (SPR), for additional information regarding the computation of earnings per share.

Regulatory Accounting and Other Regulatory Assets

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

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 current and pending or potential deregulation legislation.

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 previously reported balances as of December 31, 2003. Presented below are the balances as of September 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 SEPTEMBER 30, 2004
	Remaining	Receiving Regulatory Treatment				Pending				As of December
	Amortization	Earning a		Not Earning		Regulatory		2004		31, 2003
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total
Other Regulatory Assets
Early retirement and severance offers	Various thru 2004	$	—	$	624	$	—	$	624	$	2,497
Loss on reacquired debt	Term of Related Debt		32,310		—		—		32,310		30,123
Plant assets	Various thru 2031		42,058		7,288		—		49,346		3,414
Nevada divestiture costs	Thru 5/2012		34,138		—		—		34,138		35,164
Merger transition/transaction costs	Thru 5/2014		—		36,255		—		36,255		14,185
Merger severance/relocation	Thru 5/2014		—		20,399		—		20,399		21,375
Merger goodwill	Thru 5/2044		—		289,704		—		289,704		19,070
California restructure costs	Thru 2008		2,080		—		1,937		4,017		4,368
Conservation programs	Thru 2004		10,551		—		—		10,551		8,361
Variable rate mechanism deferral	Thru 10/2004		—		27		—		27		352
Other costs	Thru 2017		5,613		341		3,802		9,756		3,598

Total other regulatory assets		$	126,750	$	354,638	$	5,739	$	487,127	$	142,507

Regulatory Liabilities
Cost of Removal	Various	$	195,790	$	—	$	—	$	195,790	$	174,717
Gain on Property Sales	Various thru 2007		27,671		495		—		28,166		39,312
SO2 Allowances	Various thru 2010		2,015		—		—		2,015		4,129

Total regulatory liabilities		$	225,476	$	495	$	—	$	225,971	$	218,158

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF SEPTEMBER 30, 2004
	Remaining	Receiving Regulatory Treatment				Pending				As of December
	Amortization	Earning a		Not Earning		Regulatory		2004		31, 2003
DESCRIPTION	“Period	Return		a Return		Treatment		Total		Total
Other Regulatory Assets
Loss on reacquired debt	Term of Related Debt	$	13,340	$	—	$	—	$	13,340	$	13,956
Nevada divestiture costs	Thru 3/2012		20,950		—		—		20,950		21,886
Merger transition/transaction costs	Thru 3/2014		—		25,374		—		25,374		7,652
Merger severance/relocation	Thru 3/2014		—		9,692		—		9,692		10,209
Merger Goodwill	Thru 3/2044		—		194,038		—		194,038		—
Conservation programs	Thru 2005		8,223		—		—		8,223		6,809
Other costs	Various thru 2008		2,582		160		1,603		4,345		209

Total other regulatory assets		$	45,095	$	229,264	$	1,603	$	275,962	$	60,721

Regulatory Liabilities
Cost of Removal		$	115,393	$	—	$	—	$	115,393	$	104,446
Gain on Property Sales	Various thru 2007		27,669		495		—		28,164		39,312
SO2 Allowances	Various thru 2010		2,015		—		—		2,015		4,129

Total regulatory liabilities		$	145,077	$	495	$	—	$	145,572	$	147,887

SIERRA PACIFIC POWER COMPANY

OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF SEPTEMBER 30, 2004
	Remaining	Receiving Regulatory Treatment				Pending				As of December
	Amortization	Earning a		Not Earning		Regulatory		2004		31, 2003
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total
Other Regulatory assets
Early retirement and severance offers	Various thru 2004	$	—	$	624	$	—	$	624	$	2,497
Loss on reacquired debt	Term of Related Debt		18,970		—		—		18,970		16,167
Plant assets	Various thru 2031		42,058		7,288		—		49,346		3,414
Nevada divestiture costs	Thru 5/2012		13,188		—		—		13,188		13,278
Merger transition/transaction costs	Thru 5/2014		—		10,881		—		10,881		6,533
Merger severance/relocation	Thru 5/2014		—		10,707		—		10,707		11,166
Merger goodwill	Thru 5/2044		—		95,666		—		95,666		—
California Restructure Costs	Thru 2008		2,080		—		1,937		4,017		4,368
Conservation Programs	Thru 2005		2,328		—		—		2,328		1,552
Variable rate mechanism deferral	Thru 10/2004		—		27		—		27		352
Other costs	Various through 2017		3,031		181		2,199		5,411		3,389

Total other regulatory assets		$	81,655	$	125,374	$	4,136	$	211,165	$	62,716

Regulatory Liabilities
Cost of Removal	Various	$	80,397	$	—	$	—	$	80,397	$	70,271
Gain on Property Sales	Thru 2005		2		—		—		2		—

Total regulatory liabilities		$	80,399	$	—	$	—	$	80,399	$	70,271

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Deferral of Energy Costs

NPC and SPPC implemented deferred energy accounting on March 1, 2001. Beginning January 2004, the CPUC 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.

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


		September 30, 2004
		NPC		SPPC			SPPC			SPR
		Electric		Electric			Gas			Total
Description	Recovery Periods
Unamortized balances approved for collection in current rates⁽¹⁾
Electric Period 1	(effective 4/03, 3 years)	$	26,087	$	—		$	—		$	26,087
Electric Period 1	(effective 6/03, 3 years)		—		28,359			—		$	28,359
Electric Period 2	(effective 5/03, 3 years)		69,713		—			—		$	69,713
Electric Period 2	(effective 6/04, 1 year)		—		(11,655	)		—		$	(11,655	)
Electric Period 3	(effective 1/05, 27 months)		88,977		—			—		$	88,977
Electric Period 3	(effective 4/05, 27 months)		—		42,398			—		$	42,398
Natural Gas Period 1	(effective 11/01, 3 years)		—		—			2,866		$	2,866
Natural Gas Period 3	(effective 11/03, 1 year)		—		—			(5,095	)	$	(5,095	)
LPG Gas Period 2			—		—			22		$	22
Balances pending PUCN approval			—		—			3,357	⁽²⁾	$	3,357
Balances pending CPUC approval			—		1,605			—		$	1,605
Balances accrued since end of periods submitted for PUCN approval			115,865		32,782			(14	)	$	148,633
Claims for terminated supply contracts⁽³⁾			240,039		84,032			—		$	324,071

Total		$	540,681	$	177,521		$	1,136		$	719,338

Current Assets
Deferred energy costs - electric		$	58,205	$	24,701		$	—		$	82,906
Deferred energy costs - gas			—		—			1,136		$	1,136
Deferred Assets
Deferred energy costs - electric			482,476		152,820			—		$	635,296

Total		$	540,681	$	177,521		$	1,136		$	719,338

(1)

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

(2)

Balance approved for collection on October 27, 2004.

(3)

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 September 30, 2004, restricted cash and investments primarily consisted of $21.6 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 $49 million and $11 million in cash collateral deposited by NPC and SPPC, respectively, 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. The remaining amount consists of cash balances that NPC and SPPC are required to maintain as collateral to support their letters of credit.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 earnings/(loss) applicable to common stock would have changed to the pro forma amounts indicated below (dollars in thousands, except per share amounts):


		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2004			2003			2004			2003
Earnings (loss) applicable to common stock	As reported	$	90,647		$	107,772		$	1,313		$	(120,698	)
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	As reported		844			66			1,112			90
Less: Total stock employee compensation expense determined under fair value based methods, net of related tax effects	Pro forma		(863	)		(83	)		(1,168	)		(1,324	)
Pro forma earnings (loss) applicable to common stock	Pro forma	$	90,628		$	107,755		$	1,257		$	(121,932	)

Basic earnings (loss) per share	As reported	$	0.50		$	0.59		$	0.01		$	(1.05	)
	Pro forma	$	0.50		$	0.59		$	0.01		$	(1.06	)
Diluted earnings (loss) per share	As reported	$	0.50		$	0.28		$	0.01		$	(1.05	)
	Pro forma	$	0.50		$	0.28		$	0.01		$	(1.06	)

Recent Pronouncements

FIN 46 (R)

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 (QFs), jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven 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) due 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 September 30, 2004.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

FSP FAS 106-2

The Financial Accounting Standards Board (FASB) issued a Staff Position (FSP) to modify Statement of Financial Accounting Standards 106 (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 (the “Act”), signed into law on December 8, 2003. This FSP supersedes FSP FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, under which the Company elected to defer implementation due to the lack of definitive guidelines from the FASB and the Department of Health and Human Services. SPR has concluded that its prescription drug plan would qualify for the federal subsidy under this Act.

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 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 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 completed its evaluation of the impact of this Act on its postretirement benefit expense. SPR elected to adopt FSP FAS 106-2 prospectively, valuing the annual benefit of the subsidy as of April 1, 2004, and recognizing one half of this amount in the third and fourth quarters. (The April 1 valuation was required for companies using an annual measurement date of September 30 for pension plans, and electing to adopt FSP FAS 106-2 prospectively.) The valuation resulted in an annual reduction to other postretirement benefit costs of $0.8 million. Accordingly, SPR will recognize $0.2 million in each of the third and fourth quarters of 2004. Also refer to Note 13, Pension and Other Postretirement Benefits.

FSP FAS 129-1

In April 2004, the FASB issued FSP FAS 129-1, Disclosure Requirements under FASB Statement No. 129, Disclosure of Information about Capital Structure, relating to Contingently Convertible Securities to provide disclosure guidance for contingently convertible securities, including those instruments with contingent conversion requirements that have not been met and otherwise are not required to be included in the computation of diluted earnings per share. In order to comply with the requirements of FAS 129, the significant terms of the conversion features of the contingently convertible security should be disclosed including: (i) events or changes in circumstances that would cause the contingency to be met and any significant features necessary to understand the conversion rights and the timing of the rights, (ii) the conversion price and the number of shares into which the security is potentially convertible, (iii) events or changes in circumstances, if any, that could adjust or change the contingency, conversion price, or number of shares, including significant terms of those changes and (iv) the manner of settlement upon conversion and any alternative methods. SPR has adopted and implemented the disclosure requirements of FSP FAS 129-1. See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt and Note 8, Long-Term Debt, of Notes to Financial Statements in SPR’s 2003 10-K.

EITF 03-6

The Emerging Issues Task Force (EITF) of the FASB nullified the guidelines given in EITF Topic D-95 with regards to the effect of participating convertible securities on the computation of basic earnings per share by issuing EITF 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128. Under Topic D-95 (See Note 10 of the Condensed Notes to Consolidated Financial Statements, Earnings Per Share), companies were required to use either the “two-class” or the “if-converted” method to account for potential dilution due to participating convertible securities that could be converted into common stock, if the effect was dilutive. This was to be used in the calculation of basic and diluted earnings per share.

Accordingly, SPR included the dilutive effects of its convertible 7.25% notes due 2010, or Convertible Notes, in its financial statements for the three months ended September 30, 2003 using the “if-converted” method. The impact of conversion was deemed to be anti-dilutive for all other periods in 2003 and 2004 when Topic D-95 was effective. EITF 03-6 now requires using the “two-class” method to record the effect of participating securities in the computation of basic earnings per share, and the “if-converted” method in the computation of diluted earnings per share.

The FASB ratified the consensus reached by the EITF on Issue 03-6 on March 31, 2004, and made it effective for fiscal periods commencing after this date. SPR has adopted the “two-class” method to show the potential dilutive effect of its Convertible Notes in the computation of basic earnings per share for all financial statements issued after March 31, 2004.

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 the following significant uncertainties:

•

whether there would 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 would have sufficient liquidity and the ability under certain restrictions to provide dividends to SPR;

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

•

whether SPR and the Utilities would 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 would 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 November 9, 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 pendancy of the Utilities’ appeal of the Judgment to the U.S. District Court for 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 sought reversal of the Judgment and contended that Enron is not entitled to recover termination charges under the contracts on various grounds including breach of contract, breach of solvency representation, fraud, misrepresentation, and manipulation of the energy markets and that the Bankruptcy Court erred in holding that the filed rate doctrine barred various claims which were purported to challenge the reasonableness of the rate. Enron filed a cross-appeal on the grounds that the amount of post-judgment interest should have been 12% per year instead of 1.21% as ordered by the Bankruptcy Court.

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

•

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

•

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

•

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

The District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The District Court rejected Enron’s cross-appeal seeking a 12% per year post-judgment interest rate instead of the 1.21% interest rate ordered by the Bankruptcy Court. The Utilities do not know whether Enron will appeal this portion of the District Court’s decision or the timing of any such appeal. The District Court decision also provides that Enron may, if proper, renew its motion to enjoin the proceedings currently before the Federal Energy Regulatory Commission (“FERC”) addressing Enron’s termination of its power supply contracts with NPC and SPPC. The Utilities continue to assess the impact of the District Court’s decision.

Pursuant to a stipulation and agreement previously entered into among the Utilities and Enron, which was approved and filed with the Bankruptcy Court, the collateral contained in the Utilities’ escrow accounts that secured their stay of execution of the Judgment will remain in place through the pendancy of all remands and appeals through the U.S. Supreme Court.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Power Pool Agreement (“WSPPA”). Hearings were scheduled to begin on October 25, 2004 and an initial decision was expected from the FERC by December 31, 2004. However, on October 12, 2004, after learning on the same day that Enron had not produced and would not be able to produce by the scheduled October 25th hearing date approximately 900,000 documents and approximately 84,000 emails that are potentially responsive to the Utilities’ document requests, the Utilities filed an emergency motion to delay the hearings to ensure that hearings will be based on a full record after adequate time for discovery. All parties in the dispute supported the delay. As a result, on October 13, 2004, the Chief Administrative Law Judge at the FERC suspended the prior deadline for an initial decision in the matter from December 31, 2004 to February 14, 2005. The hearings have been rescheduled for the week of December 13, 2004. The Utilities are unable to predict the outcome of this FERC proceeding or whether FERC’s decision will affect the Bankruptcy Court’s reconsideration of this matter and any subsequent appeals of the Judgment or related matters and cases.

Financing, Liquidity and Other Matters

NPC and SPPC anticipate capital requirements for construction costs in 2004 will be approximately $473 million and $112 million, respectively, of which $160 million and $66 million, respectively, were incurred through September 30, 2004, and capital requirements for construction costs in 2005 will be approximately $618 million and $170 million, respectively. The Utilities expect to finance these costs with internally generated funds, including the recovery of deferred energy, and with new secured debt. Through October 31, 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. NPC has also put into place credit facilities to support the purchase of the Chuck Lenzie Generating Station (formerly known as Moapa Energy Facility) and its associated 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.

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 $10.2 million at September 30, 2004, which does not include restricted cash and investments of approximately $21.6 million. The $21.6 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 excluding interest on SPR’s 7.25% Convertible Notes. Excluding interest on SPR’s 7.25% Convertible Notes, SPR paid approximately $72.2 million of debt service obligations on its existing debt securities during the nine months ended September 30, 2004. SPR has approximately $5.4 million payable of debt service obligations remaining during 2004. Currently, SPR expects to meet its remaining debt service obligations for 2004 and 2005 of approximately $5.4 million and $50.5 million, respectively, 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.

On September 21, 2004, the PUCN issued its decision on NPC’s 2003 Amended Resource Plan, approving the acquisition of a partially completed power plant and granting enhanced recovery of the facility. On October 13, 2004, following the PUCN decision, NPC completed the acquisition of the facility from Duke.

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

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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

Following the remand ordered by the District Court, the merits of the termination of the power contracts by Enron may be heard by the Bankruptcy Court while being heard concurrently by the FERC. Further legal proceedings may arise to determine the proper venue and jurisdiction for the pending claims. The Utilities are unable to determine which forum will ultimately be found to have jurisdiction over these matters in the event that a jurisdictional conflict should arise.

The Utilities may seek clarification from the District Court on whether various issues not addressed in the District Court’s decision have been reserved for a later determination including the judgment entered by the Bankruptcy Court in favor of Enron for power previously delivered to the Utilities. If the Utilities do not prevail on the remand of the case to the Bankruptcy Court, they may seek a further appeal. Enforcement of any judgment that might be obtained by Enron against the Utilities would likely be stayed pursuant to the parties’ stipulation and agreement (discussed above); however, there can be no assurances a court hearing the case or an appeal of the case would accept the collateral arrangement without modification in the event that a subsequent judgment were entered against the Utilities.

The Utilities continue to pursue their FERC Section 206 complaint against Enron. In the event that the FERC rules against the Utilities, the Utilities would have the right to appeal the FERC’s decision to a federal Circuit Court.

If Enron were to obtain a final non-appealable judgment against the Utilities, management believes that the Utilities would have the means to pay any such judgment. The Utilities previously 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, Series E 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 together with the cash in escrow in the event that the Utilities had to pay a judgment in favor of Enron.

If the Utilities are unsuccessful in the remarketing of the Bonds or if Enron chose 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 claims and/or judgments against the Utilities. 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 Utilities are ultimately required to pay Enron for liquidated damages associated with the terminated power supply contracts, the Utilities would pursue recovery of such amounts through their 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 claims against the Utilities 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 and 2005.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Regulatory Matters

The Utilities continue to work 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 have implemented new energy risk management and fuel procurement polices, which are designed to stabilize the Utilities’ risk exposure in the energy market.

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 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. In accordance with regulation, NPC’s energy supply plan for 2004/2005 was filed with the PUCN in September 2004 with a decision expected by the end of 2004. SPPC’s energy supply plan was filed along with its resource plan in July 2004, which includes among other things, a new 500 MW plant to be built by the summer of 2008. A decision on the SPPC plan is expected by mid-November 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 assurance 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
September 30, 2004	Electric		Electric		Electric		Gas			Other		Eliminations		Consolidated
Operating Revenues	$	633,609	$	253,615	$	887,224	$	16,387		$	304	$	—	$	903,915

Operating Income (Loss)	$	120,842	$	39,262	$	160,104	$	(207	)	$	2,371	$	—	$	162,268


Three Months Ended	NPC		SPPC		Total							Reconciling
September 30, 2003	Electric		Electric		Electric		Gas			Other		Eliminations		Consolidated
Operating Revenues	$	639,661	$	250,476	$	890,137	$	13,931		$	279	$	—	$	904,347

Operating Income (Loss)	$	127,737	$	32,750	$	160,487	$	(162	)	$	4,822	$	—	$	165,147

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Nine Months Ended	NPC		SPPC		Total						Reconciling
September 30, 2004	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	1,410,067	$	657,881	$	2,067,948	$	97,742	$	3,762	$	—	$	2,169,452

Operating Income	$	191,312	$	80,270	$	271,582	$	4,319	$	7,187	$	—	$	283,088

Assets⁽¹⁾	$	4,659,639	$	2,207,300	$	6,866,939	$	242,693	$	181,330	$	52,736	$	7,343,698


Nine Months Ended	NPC		SPPC		Total						Reconciling
September 30, 2003	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	1,396,825	$	660,956	$	2,057,781	$	114,421	$	908	$	—	$	2,173,110

Operating Income	$	155,634	$	44,149	$	199,783	$	4,209	$	14,171	$	—	$	218,163

(1)

SFAS 131 requires disclosures of segment assets on an interim basis if changes are material. See Note 1 of the Condensed Notes to Consolidated Financial Statements, Summary of Significant Accounting Policies, Regulatory Accounting and Other Regulatory Assets, for regulatory assets that have been recognized since December 31, 2003, and that have materially affected segment asset balances.

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 requested a $142 million increase in the annual revenue requirement for general rates.

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 BCP filed a petition with the PUCN requesting reconsideration and clarification of the PUCN’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, respectively. 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 June 7, 2004 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. On October 16, 2004, NPC filed a petition requesting that delayed implementation and ordered or anticipated changes be made at the same time on April 1, 2005 in order to stabilize rates and reduce the number of rate changes.

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 6 1/2% General and Refunding Mortgage Notes, Series I, due 2012 and for its $100 million revolving credit facility that was established on May 4, 2004.

On October 22, 2004 the original May 4, 2004 $100 million revolving credit facility was terminated. Using the same $100 million in available regulatory authority thus freed up due to that termination, the terminated original revolver was replaced by increasing the size of the Lenzie related $250 million revolving credit facility by $100 million, to a total of $350 million.

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 requested PUCN authorization to acquire a partially completed power plant, the “Chuck Lenzie Generating Station,” from Duke Energy for $182 million. This amendment requested approval to substitute the 1200 MW Chuck Lenzie Generating Station, which is expected to become operational in early 2006, for the previously approved Harry Allen 520 MW combined cycle generator, which is to come on line in 2007.

NPC requested that the Chuck Lenzie Generating Station 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 requested a 5% ROE incentive and specific regulatory asset treatment for this facility.

The Chuck Lenzie Generating Station is comprised of two 600 MW combined cycle generators located 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 cost $558 million.

The PUCN held hearings to consider the Resource Plan amendment and an associated financing filing and rendered an order on September 21, 2004. The PUCN granted NPC’s request for a critical facility designation and allowed for a 2% enhancement of the authorized ROE to be applied to the rate base associated with the Lenzie construction costs expended after acquisition. The PUCN also granted NPC’s request for $500 million in long-term debt authority. The order allows for up to an additional 1% enhanced ROE if the two Lenzie generator units are brought on line early and the gradual elimination of the enhanced ROE if completion is delayed. The order allows NPC to include the plant investments during construction in rate base when NPC files its regularly scheduled general rate cases, which permits NPC to earn a return during construction. The PUCN also granted NPC’s request to establish regulatory asset accounts to prevent the erosion of earnings, which otherwise would occur due to regulatory lag. The regulatory asset account will capture the depreciation expense and return on rate base between the time the plant is placed in service and when the plant costs are included in rates.

The transaction with Duke Energy closed on October 13, 2004. A future general rate case will be required before NPC can include the costs for this facility in customers’ rates.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 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.

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 filed its opening brief in early October. Answering and Reply briefs are scheduled for November and December and the hearings are expected to occur in the first quarter of 2005. 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.

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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 6¼% 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, which was terminated and replaced with a $75 million Revolving Credit Facility, $50 million of which is long-term under this 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 a “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 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.

Intervener’s filed testimony on September 24, 2004. The following summarizes their positions on significant issues:

•

Critical facility designation and associated enhanced ROE for investment in 500 MW combined cycle plant

The Staff recommended that the PUCN authorize SPPC to go forward with permitting and development activities associated with the construction of the Tracy 500 MW combined cycle project, but require SPPC to file a resource plan amendment on or before August 1, 2005, to reaffirm the need for the 500 MW capacity addition and to clarify the cost, timing and configuration of the project to be constructed. The Staff also requested that the PUCN withhold any finding of whether the facility should be classified as a “critical facility” until the amended filing is made. The BCP argued that the facility should not be classified as a critical facility or in the event that it is classified as a critical facility, to reduce the requested incentive package.

•

Energy Supply Plan

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The BCP takes issue with SPPC’s energy supply plan and recommends the PUCN order SPPC, the Staff and other parties to identify and evaluate other procurement approaches.

SPPC and parties reached agreement on the issues and presented their stipulation to the PUCN on October 12, 2004. The stipulation calls for budget adjustments in the Demand Side Management programs and continued discussions to develop a new cost/benefit test for such programs. The stipulation authorizes SPPC to proceed with permitting activities for a 500 MW combined cycle power plant as requested and requires the Company to file a Resource Plan Amendment to reaffirm the need for the 500MW capacity addition before August 1, 2005. SPPC’s request for a “critical facility” designation and the associated enhanced ROE was deferred for consideration during the amendment proceedings. All other supply side proposals were approved as filed. A Commission order is expected to be rendered on or before November 13, 2004.

Sierra Pacific Power Company Annual Purchased Gas Cost Adjustment

On May 14, 2004, SPPC filed its annual application for Purchased Gas Cost Adjustment for its natural gas local distribution company. In the application, SPPC asked for an increase of $0.09456 per therm to its Base Purchased Gas Rate to recover its expected going forward gas costs. SPPC also requested that $0.02857 per therm be added to the Balancing Account Adjustment (BAA) rate to amortize an approximate $3.9 million balance of deferred gas costs, which were accumulated during the accounting period. Combined with the simultaneous expiration of past BAA charges, the new BAA rate would be $.03869 per therm less than the current BAA rate. Overall, this request would result in a rate increase of approximately 5%.

The parties agreed to a stipulation, which recommended the PUCN approve the requested rates and the PUCN issued an order approving the rate increase on October 27, 2004.

NOTE 5. SHORT-TERM BORROWINGS

Sierra Pacific Power Company

Revolving Credit Facility

On October 22, 2004, SPPC terminated its $50 million long-term revolving credit facility, which had been established on May 4, 2004, and replaced it with a three-year revolving credit facility of $75 million. In this new credit facility, $25 million of the $75 million is short-term (364 day) until such time as the utility receives long-term debt authority from the PUCN for the additional $25 million. SPPC has not yet determined whether it will seek such long-term authority.

NOTE 6. LONG-TERM DEBT

As of September 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):


							SPR Holding Co. and
	NPC			SPPC			Other Subs.⁽¹⁾			SPR Consolidated
Balance of 2004	$	(317	)⁽²⁾	$	521		$	11,550		$	11,754
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

		25,298			380,121			251,768			657,187
Thereafter		2,016,023			617,850			635,000	⁽³⁾		3,268,873

		2,041,321			997,971			886,768			3,926,060
Unamortized (Discount Amount)		(10,365	)		(760	)		(6,303	)		(17,428	)

Total	$	2,030,956		$	997,211		$	880,465		$	3,908,632

(1)		SPR Holding Co. and Other Subs. includes the debt of Sierra Pacific Communications of $11.6 million which is included in “Liabilities of Discontinued Operations”. See Note 12 in the Condensed Notes to Consolidated Financial Statements, Disposal of Assets.

(2)		Indicates excess of payments over accrual of liability for capital leases.

(3)		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 $239.9 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Nevada Power Company

General and Refunding Mortgage Notes, Series I

On April 7, 2004, NPC issued and sold $130 million of its 6½% 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 Notes, Series G Notes and Series H Bond, 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 Investor 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.

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.

Chuck Lenzie Generating Station Related Revolving Credit Facility

On October 8, 2004, NPC entered into a $250 million Credit Agreement with Union Bank of California, N.A., as Administrative Agent, to finance the purchase price of the Chuck Lenzie Generating Station (the “Facility”), to pay fees, costs and expenses incurred by NPC in connection with the purchase and construction of the Facility and for general corporate purposes. On October 22, 2004, NPC amended and restated the Credit Agreement to increase the total size of the revolving credit facility to $350 million, concurrently with its termination of its $100 million Credit Facility, which was established on May 4, 2004. The new revolving credit facility, which is secured by NPC’s $350 million General and Refunding Mortgage Bond, Series K, will expire October 8, 2007. The rate for outstanding loans and/or letters of credit under revolving credit facility will be at either an alternate base rate or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s alternate base rate margin is 1.00% and its Eurodollar margin is 2.00%.

On October 8, 2004, NPC borrowed $150 million under the revolving credit facility to pay part of the $182 million purchase price for the Facility. The remainder of the purchase price was funded with available cash.

The NPC Credit Agreement contains two financial maintenance covenants. The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.

The NPC Credit Agreement, similar to NPC’s Series E Notes, Series G Notes, Series H Bond and Series I Notes, 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Credit Agreement also contains a restriction on NPC’s ability to incur additional indebtedness which is similar to the restriction discussed above for NPC’s Series I Notes.

Among other things, the NPC Credit Agreement 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.

The NPC Credit Agreement provides for certain events of default including any of the following events: NPC fails to make payments of principal or interest under the Credit Agreement, NPC fails to comply with certain agreements included in the Credit Agreement, NPC files for bankruptcy, or a change of control occurs. The Credit Agreement also provides for an event of default if a judgment of $15 million or more is entered against NPC and such judgment is not vacated, discharged, stayed or bonded pending appeal within 60 days. Since, the Credit Agreement also prohibits the creation or existence of any liens on NPC’s properties except for liens specifically permitted under the Credit Agreement, if a judgment lien is filed against NPC, the filing of the lien will trigger an event of default under the Credit Agreement. The Credit Agreement also provides for an event of default if NPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million.

Upon an event of default, the Administrative Agent under the NPC Credit Agreement may, upon request of more than 50% of the lenders under the Credit Agreement, declare all amounts due under the Credit Agreement immediately due and payable. Since NPC’s obligations under the Credit Agreement are secured by its General and Refunding Mortgage Bond, if NPC fails to repay all amounts due upon an acceleration of the Credit Agreement within three business days, such failure will be deemed a default in the payment of principal and will trigger an event of default under the NPC General and Refunding Mortgage Indenture that would be applicable to all securities issued under the NPC General and Refunding Mortgage Indenture.

$100 million Revolving Credit Facility

On May 4, 2004, NPC established a $100 million Revolving Credit Facility with a maturity date of May 4, 2009. Borrowings under this facility were secured by NPC’s General and Refunding Mortgage Bond, Series J, due 2009. 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.

Concurrent with the amendment and restatement of the new $350 million revolving credit facility, discussed above, this facility was terminated on October 22, 2004. There were no amounts outstanding under this facility at the time of termination.

Sierra Pacific Power Company

General and Refunding Mortgage Notes, Series H

On April 16, 2004, SPPC issued and sold $100 million of its 6¼% 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, similar to SPPC’s Series E Bond, 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, as with the Series E Bond, 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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 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 October 22, 2004, SPPC entered into a $75 million Credit Agreement with Union Bank of California, N.A., as Administrative Agent. Borrowings under this revolving credit facility will be used for SPPC’s general corporate purposes. The revolving credit facility, which is secured by SPPC’s $75 million General and Refunding Mortgage Bond, Series L, will expire on October 22, 2007. The rate for outstanding loans and/or letters of credit under revolving credit facility will be at either an alternate base rate or a Eurodollar rate plus a margin that varies based upon SPPC’s credit rating by S&P and Moody’s. Currently, SPPC’s alternate base rate margin is 1.00% and its Eurodollar margin is 2.00%. SPPC has not borrowed any amounts under this revolving credit facility.

Upon the effectiveness of the Credit Agreement, SPPC terminated its previously existing $50 million synthetic revolving credit facility, which it entered into on May 4, 2004. No amounts were outstanding under this facility at the time of termination.

The SPPC Credit Agreement contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.

Due to a negative pledge obligation in SPPC’s Series E Bond, which was issued to an escrow agent to secure Enron’s judgment against SPPC (see Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies), SPPC expects to amend its Series E Bond to include these two financial maintenance covenants. Although the judgment was vacated in a decision handed down on October 10, 2004 by the U.S. District Court for the Southern District of New York, SPPC’s Series E Bond will continue to remain in escrow through the pendancy of all remands and appeals pursuant to a stipulation and agreement previously entered into among NPC, SPPC and Enron.

The Credit Agreement, similar to SPPC’s Series H Notes and Series E Bond, 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 Credit Agreement also contains a restriction on SPPC’s ability to incur additional indebtedness which is similar to the restriction discussed above for SPPC’s Series H Notes and Series E Bond.

Among other things, the SPPC Credit Agreement 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.

The SPPC Credit Agreement provides for certain events of default including any of the following events: SPPC fails to make payments of principal or interest under the Credit Agreement, SPPC fails to comply with certain agreements included in the Credit Agreement, SPPC files for bankruptcy, or a change of control occurs. The Credit Agreement also provides for an event of default if a judgment of $15 million or more is entered against SPPC and such judgment is not vacated, discharged, stayed or bonded pending appeal within 60 days. Since, the Credit Agreement also prohibits the creation or existence of any liens on SPPC’s properties except for liens specifically permitted under the Credit Agreement, if a judgment lien is filed against

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SPPC, the filing of the lien will trigger an event of default under the Credit Agreement. The Credit Agreement also provides for an event of default if SPPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million.

Upon an event of default, the Administrative Agent under the SPPC Credit Agreement may, upon request of more than 50% of the lenders under the Credit Agreement, declare all amounts due under the Credit Agreement immediately due and payable. Since SPPC’s obligations under the Credit Agreement are secured by its General and Refunding Mortgage Bond, if SPPC fails to repay all amounts due upon an acceleration of the Credit Agreement within three business days, such failure will be deemed a default in the payment of principal and will trigger an event of default under the SPPC General and Refunding Mortgage Indenture that would be applicable to all securities issued under the SPPC General and Refunding Mortgage Indenture.

$50 million Revolving Credit Facility

On May 4, 2004, SPPC established a $50 million Revolving Credit Facility with a maturity date of May 4, 2008. Borrowings under this facility were evidenced on SPPC’s General and Refunding Mortgage Bond, Series K, due 2008.

As of September 30, 2004, SPPC had not drawn on this Revolving Credit Facility.

Concurrent with the establishment of its new $75 million revolving credit facility, discussed above, this existing facility was terminated on October 22, 2004. No amounts were outstanding under this facility at the time of termination.

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 8¾% 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 8¾% 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:

	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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SPR Corporate Premium Income Equity Securities (PIES)

PIES Outstanding

On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate Premium Income Equity Securities (PIES). Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50.

On February 5, 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its common stock in five privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933. As of September 30, 2004, 4,804,350 PIES and approximately $240 million of senior unsecured notes remain outstanding.

PIES Conversion Features

Each stock purchase contract obligates the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor is entitled to receive will depend on the average closing price of SPR common stock over a 20-day trading period prior to the settlement. The total number of common shares SPR will issue upon settlement of the applicable portion of the stock purchase contract on the settlement date will be determined based upon the following criteria.

	•		A Threshold Appreciation Price was set at $16.62 per share, which was approximately 20% above the last reported sale price of SPR common stock on November 12, 2001, which was $13.85 (the Reference Price).

	•		If the Applicable Market Value (the 20-trading-day average closing price per share of SPR common prior to the settlement date) is greater than or equal to the Threshold Appreciation Price of $16.62, then the Settlement Rate will be 3.0084 common shares per purchase contract. This is equivalent to shares being issued at a market price of $16.62 (i.e. $50 / $16.62 = 3.0084).

	•		If the Applicable Market Value is less than the Threshold Appreciation Price of $16.62 but greater than the Reference Price of $13.85, then the Settlement Rate will be equal to $50 divided by the Applicable Market Value (the 20-trading-day average closing price per share of SPR common prior to the settlement date) to arrive at the number of common shares per purchase contract.

	•		If the Applicable Market Value is less than or equal to the Reference Price of $13.85, then the Settlement Rate will be 3.6101 common shares per purchase contract. This is equivalent to shares being issued at a market price of $13.85 (i.e. $50 / $13.85 = 3.6101).

In no instance will fractional shares will be issued; cash will be paid in lieu of any fractional shares.

PIES Settlement Options

The senior notes are pledged as collateral to secure each holder’s obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations. If any senior notes remain outstanding after the Purchase Contract Settlement Date, SPR will pay interest payments on those senior notes until their maturity on November 15, 2007.

PIES Range of Common Shares to be Issued

At September 30, 2004 there were 4,804,350 SPR PIES outstanding. Depending on the Applicable Market Value on the Settlement Date of November 15, 2005, the range of SPR common shares to be issued would vary between a high of approximately 17,344,000 shares if the common share Applicable Market Value was less than or equal to $13.85, to a low of approximately 14,453,000 shares if the common share Applicable Market Value was greater than or equal to $16.62.

The September 30, 2004 SPR common stock closing price was $8.95 per share. The Applicable Market Value (the 20-trading-day average closing price per share) inclusive of September 30 was $8.86 per SPR common share. Using that

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

average price of $8.86 the criteria of an Applicable Market Value less than or equal to the Reference Price of $13.85 would have been determinate. Thus, utilizing the criteria above, the Settlement Rate would be 3.6101 common shares per purchase contract.

Given the current balance of 4,804,350 PIES outstanding, approximately 17,344,184 (4,804,350 times 3.6101 minus any fractional shares) SPR common shares would be issued at the Settlement Date of November 15, 2005.

For a discussion of the potential effect of this conversion on earnings per share please see Note 10 of the Condensed Notes to Consolidated Financial Statements, Earnings Per Share.

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.

•

The following notes, bonds and credit agreement limit the amount of payments in respect of common stock that NPC may make to SPR:

	•		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 6½% General and Refunding Mortgage Notes, Series I, due 2012, which were issued on April 7, 2004,

	•		NPC’s Revolving Credit Agreement, which was established on October 8, 2004 in connection with the purchase of the Chuck Lenzie Generating Station, and amended and restated on October 22, 2004.

However, the dividend payment 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:

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

The terms of the 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, the Series H Bond, and the NPC 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 NPC 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 Agreement, 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

•

The following notes, bonds and credit facilities limit the amount of payments in respect of common stock that SPPC may make to SPR:

	•		SPPC’s Revolving Credit Agreement, which was established on October 22, 2004,

	•		SPPC’s 6¼% General and Refunding Mortgage Notes, Series H, due 2012, which were issued on April 16, 2004, and

	•		SPPC’s General and Refunding Mortgage Bond, Series E, which was issued on December 4, 2003.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

However, the dividend payment 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.

The terms of the Series H Notes, the SPPC 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 SPPC 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 and 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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			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 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. Although the judgment has been reversed by the U.S. District Court of the Southern District of New York, this limitation will remain in place pursuant to the terms of a stipulation and agreement among the Utilities and Enron.

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 payable or recoverable 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):


	September 30,									December 31,
	2004									2003
	SPR			NPC			SPPC			SPR		NPC		SPPC
Risk management assets	$	36.5		$	14.1		$	22.4		$	22.1	$	11.7	$	10.4
Risk management liabilities	$	3.2		$	1.5		$	1.7		$	16.5	$	5.2	$	11.3
Risk management regulatory assets (liabilities)		($14.7	)		($4.3	)		($10.3	)	$	14.3	$	3.1	$	11.2

Also included in SPR’s, NPC’s and SPPC’s risk management assets were $18.4 million, $8.2 million, and $10.2 million in payments for gas options, respectively, at September 30, 2004.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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 Mohave would 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 by the end of 2005. The net book value as of September 30, 2004 is $39.5 million. Alternatively, NPC requested that the PUCN authorize the transfer of the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN. 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 $33.4 million, of which, approximately $18.8 million has been spent through 2003. Estimated total capital expenditures in 2004 and 2005 are approximately $1.4 million and $5.8 million, respectively.

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

procedures, and recorded oil/coal data pertaining to the sources identified in the Title V permit were requested. NPC has provided information in connection with this request and subsequent requests. In September and October 2004, NPC met with the NDEP to review the outcome of their inspection. NDEP informed NPC that it may not be in compliance with certain aspects of its Title V permit and is likely to issue a Notice of Alleged Violation (NOAV), unless, NPC provides additional documentation which supports its compliance with Title V permit regulations. NPC is continuing to provide information to NDEP as requested. Because NPC has not received a NOAV, management cannot reasonably estimate any potential monetary penalties at this time.

In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. On October 31, 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. 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 (collectively, the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRPs formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA issued an administrative order on consent requiring the steering committee to oversee the performance of the work. 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 is expected to be installed in December 2004 and remediation should be complete by April 2005. 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 its assertion that the Utilities did not provide adequate assurance of the Utilities’ performance under the WSPPA. The Utilities dispute that they owe the monies sought by Enron and have denied liability on numerous grounds, including termination, deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.

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

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 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.”

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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On October 1, 2004, the Bankruptcy Court ruled that Enron was entitled to take the $17.7 million and $6.7 million deposited by NPC and SPPC, respectively, for power previously delivered to them, out of escrow for the benefit of Enron’s bankruptcy estate. The Utilities have challenged and appealed the Bankruptcy Court’s order with respect to these payments.

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

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

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

The District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The District Court rejected Enron’s cross-appeal seeking a 12% per year post-judgment interest rate instead of the 1.21% interest rate ordered by the Bankruptcy Court. The Utilities do not know whether Enron will appeal this portion of the District Court’s decision or the timing of any such appeal. The District Court decision also provides that Enron may, if proper, renew its motion to enjoin the proceedings currently before the FERC addressing Enron’s termination of its power supply contracts with NPC and SPPC. The Utilities continue to assess the impact of the District Court’s decision. Although the Judgment has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron, discussed above, will remain in place through the pendency of all remands and appeals of the Judgment.

The Utilities filed a motion seeking clarification of the District Court rulings with respect to the Utilities’ claims regarding: fraud by Enron, violation of the Racketeer Influence Corrupt Organizations Act (RICO), anti-trust activities carried out by Enron, the constitutional power of a bankruptcy court to enter a final judgment in a “non-core matter,” and whether the Bankruptcy Court had properly determined the interest rate applicable to pre-judgment interest.

Through September 30, 2004, interest costs related to the Judgment of $38.4 million and $16.7 million for NPC and SPPC, respectively, were charged as interest expense and were not included in their deferred energy balances. If the Utilities obtain a final decision or other determination or resolution in their favor, 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 obtain a final non-appealable decision not in their favor, they may seek to recover the interest costs in the deferred account.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

delay. As a result, on October 13, 2004, the Chief Administrative Law Judge at the FERC suspended the prior deadline for an initial decision in the matter from December 31, 2004 to February 14, 2005. The hearings have been rescheduled for the week of December 13, 2004. The Utilities are unable to predict the outcome of this FERC proceeding or whether FERC’s decision will affect the Bankruptcy Court’s reconsideration of this matter and any subsequent appeals of the Judgment or related matters and cases. On October 27, 2004, Enron filed a motion in the Bankruptcy Court to enjoin the Utilities from participating in the FERC 206 proceeding. The Utilities plan to oppose the motion and a hearing is scheduled for late November 2004.

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 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 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). On August 11, 2004, NPC filed a motion to continue the stay, and on October 4, 2004, the Court granted the stay for another 90 days. 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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. Discovery is ongoing. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

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 an agreement 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 were 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. SPC pursued litigation in TAI’s bankruptcy case to resolve its obligations to, and claims against, TAI and its affiliates. After more than a year of litigation and extensive negotiations among various parties, SPC entered into a settlement agreement dated July 28, 2004, with TAI, STA, and AT&T. The bankruptcy court approved TAI’s plan of liquidation and the settlement agreement by order was entered on October 6, 2004. The settlement, stipulates that SPC will pay a total of $10 million to STA, $6 million of which was paid to STA in July 2004, and grant STA three ducts plus SPC’s portion of fiber in the main cable in satisfaction of the remaining amount due on the $35 million promissory note. In October 2004, SPC paid $4 million, the remaining balance provided for under the settlement, and $2.3 million in satisfaction of the various complaints and mechanics liens mentioned above. See Note 12 in the Condensed Notes to Consolidated Financial Statements, Disposal of Assets.

Other Legal Matters

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

Contract Termination Liabilities

Nevada Power Company and Sierra Pacific Power Company

At September 30, 2004, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” were approximately $273 million and $106 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 September 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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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.

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. 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 (AB 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 September 30, 2004, are $355.9 million and $116.8 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Goodwill and Merger Costs

The order issued by the PUCN in December 1998 approving the merger of SPR and NPC directed both NPC and SPPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order specifically directed both Utilities to defer merger transaction costs, transition costs and goodwill costs for a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order 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 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 and Note 11 of the Condensed Notes to Consolidated Financial Statements, Goodwill, for more information regarding the PUCN orders and future recovery of merger costs.

Generation Divestiture Costs

As a condition to 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 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 and SPPC’s petition for judicial review.

Other Contingencies

Farad Dam

SPPC owns 4 hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. Sale of the assets is dependent on CPUC approval. Although approval was expected from the CPUC in the spring of 2004, the CPUC is yet to authorize the transfer and the timing of their decision is not known.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam. SPPC filed a claim with the insurers for the flume and dam and in December 2003, SPPC sued the insurers in Federal Court on a coverage dispute relating to potential rebuild costs. The current estimate to rebuild the diversion dam is approximately $20 million. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts. Accordingly, management has not recorded a loss contingency for the cost to rebuild the dam.

NOTE 10. EARNINGS PER SHARE (EPS)

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

The Emerging Issues Task Force (EITF) of the FASB nullified the guidelines given in EITF Topic D-95 with regards to the effect of participating convertible securities on the computation of basic EPS, by issuing EITF 03-6. Under Topic D-95, companies were required to include the effect of participating securities that are convertible to common stock in basic EPS, using either the “if-converted” or the “two-class” method, if the effect was dilutive. Accordingly, SPR included the dilutive effects of its Convertible Notes in its financial statements for the three months ended September 30, 2003 using the “if- converted” method. The impact of conversion was deemed to be anti-dilutive for all other periods in 2003 and 2004 when Topic D-95 was effective. EITF 03-6 now requires using the “two-class” method to record the effect of participating securities in the computation of basic EPS, and the “if-converted” method in the computation of diluted EPS. SPR adopted EITF 03-6 for financial statements issued after March 31, 2004. The “two-class” method was used to calculate basic EPS for all periods presented except for the nine months ended September 30, 2003, when the effect was anti-dilutive due to a net loss.

The effect of using the “if-converted” method to calculate diluted EPS was found to be anti-dilutive for all periods presented except for the three months ended September 30, 2003.

The following table outlines the calculation for EPS:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Basic EPS
Numerator ($000)
Income / (loss) from continuing operations	$	91,749		$	109,978		$	8,007		$	(86,640	)
Income / (loss) from discontinued operations and on disposal of subsidiary	$	(127	)	$	(1,231	)	$	(3,769	)	$	(31,133	)
Income / (loss) applicable to outstanding common stock	$	58,100		$	69,036		$	841		$	(76,864	)
Income / (loss) applicable to convertible notes	$	32,547		$	38,736		$	472		$	(43,834	)

Net Income / (loss) for basic EPS	$	90,647		$	107,772		$	1,313		$	(120,698	)
Denominator
Weighted average common shares outstanding		117,368,001			117,177,323			117,296,081			115,294,693
Shares issuable upon conversion		65,749,110			65,749,110			65,749,110			—

Shares used for basic EPS		183,117,111			182,926,433			183,045,191			115,294,693
Per-Share Amount
Income / (loss) from continuing operations	$	0.50		$	0.60		$	0.04		$	(0.75	)
Income / (loss) from discontinued operations and on disposal of subsidiary	$	—		$	(0.01	)	$	(0.02	)	$	(0.27	)
Income / (loss) applicable to outstanding common stock	$	0.50		$	0.59		$	0.01		$	(1.05	)
Income / (loss) applicable to convertible notes	$	0.50		$	0.59		$	0.01		$	—

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004				2003
Diluted EPS
Numerator ($000)
Income / (loss) from continuing operations⁽¹⁾	$	91,749		$	53,784		$	8,007			$	(86,640	)
Income / (loss) from discontinued operations and on disposal of subsidiary	$	(127	)	$	(1,231	)	$	(3,769	)		$	(31,133	)
Income / (loss) applicable to common stock⁽¹⁾	$	90,647		$	51,578		$	1,313			$	(120,698	)
Denominator
Weighted average common shares outstanding⁽²⁾		183,117,111			182,926,433			183,045,191				115,294,693
Stock options		—			—			—				—
Executive long term incentive plan — restricted shares		—			67,084			—				—
Non-Employee Director stock plan		—			19,629			—				—
Employee stock purchase plan		—			1,725			—				—
Weighted average common shares outstanding after dilution^(3) (4)		183,117,111			183,014,871			183,045,191				115,294,693

Per-Share Amount⁽⁵⁾
Income / (loss) from continuing operations	$	0.50		$	0.29		$	0.04			$	(0.75	)
Income / (loss) from discontinued operations and on disposal of subsidiary	$	—		$	(0.01	)	$	(0.02	)	��	$	(0.27	)
Income / (loss) applicable to common stock	$	0.50		$	0.28		$	0.01			$	(1.05	)

(1)

Due to their dilutive effect on earnings per share, income from continuing operations and income applicable to common stock for the three months ended September 30, 2003 were adjusted by adding back interest expense of $3.5 million (net of tax), adding accretion expense of $1.8 million, and by subtracting the unrealized gain on derivative of $61.5 million. A calculation for the three months ended September 30, 2003 follows showing the effect of the “if-converted” method on net income.


	Three Months
	Ended September 30,
	2003
Income from continuing operations	$	109,978
Interest expense on Convertibles (net of tax)		3,535
Accretion expense on Convertibles		1,784
Unrealized gain on derivative		(61,513	)

Revised income from continuing operations	$	53,784

Income applicable to common stock	$	107,772
Interest expense on Convertibles (net of tax)		3,535
Accretion expense on Convertibles		1,784
Unrealized gain on derivative		(61,513	)

Revised income applicable to common stock	$	51,578

(2)		Weighted average number of shares outstanding for the three months ended September 30, 2003 and 2004, and nine months ended September 30, 2004 was adjusted by adding 65,749,110 shares for the Convertible Notes as of the beginning of each period.

(3)		The denominator does not include anti-dilutive stock equivalents for the Stock Option Plan and Corporate PIES, due to conversion prices being higher than market prices at three months ended September 30, 2003. The amounts that would be included in the calculation if the conversion price were met would be 1.4 million shares for the Stock Option Plan and 17.3 million shares for Corporate PIES.

(4)		The denominator for the three months ended September 30, 2004 and nine months ended September 30, 2004 and 2003 does not include anti-dilutive shares for stock options, executive long term incentive plan — performance shares, executive long term incentive plan — restricted shares, non-employee Director stock plan, and the Employee stock purchase plan. The amounts excluded are 1.4 million for each period in 2004, and 1.5 million shares for each period in 2003.

(5)		Basic EPS is presented for the three months ended September 30, 2004 and nine months ended September 30, 2004 and 2003 due to the anti-dilutive effect of the “if-converted” method.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 beginning April 1, 2004, which is based on a forty-year amortization of NPC’s total goodwill. The amount to be recovered over the next two years reflects a reduction of 20% from the amounts sought by NPC, or approximately $1 million per year, due to 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 the financial statements of 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 beginning June 1, 2004, 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 the financial statements of 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 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The change in the carrying amount of goodwill for the nine month period ended September 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 September 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 September 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 also concluded to dispose of SPC’s Long Haul Assets as part of a settlement with Touch America and Sierra Touch America (STA) in their bankruptcy proceeding. The settlement, which received final approval on October 4, 2004, stipulates that SPC will pay a total of $10 million to STA, $6 million of which was paid to STA in July 2004, and grant STA three ducts plus SPC’s portion of fiber in the main cable in satisfaction of the remaining amount due on the $35 million promissory note ($11.5 million as of September 3, 2004). In October 2004, SPC paid $4 million, the remaining balance provided for under the settlement and $2.3 million to resolve other claims discussed in Note 9, Commitments and Contingencies, Litigation Contingencies, Touch America and Sierra Touch America LLC. The settlement also gives SPC title to one remaining duct and permits SPC to complete the sale of this duct under a 2002 contract with a telecommunications carrier for $20 million. SPC recognized an impairment, in June 2004, of approximately $4.8 million (pretax) in connection with the anticipated sale of the Long Haul Assets. To the extent the final sales price and other closing costs differ from our estimate, an adjustment will be made to impairment recognized in June 2004.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The assets and liabilities associated with the discontinued operation of SPC are segregated on the consolidated balance sheets at December 31, 2003 and September 30, 2004. Revenues from SPC for the nine months ended September 30, 2004 and 2003 were $957,000 and $1.2 million, respectively, and pre-tax loss of approximately $5.9 million and $36.6 million. The carrying amount of major asset and liability classifications are as follows (dollars in thousands):


	September 30,		December 31,
	2004		2003
Investments and other property, net	$	30,127	$	36,512
Cash		51		32
Current assets — Other		—		3,528

	$	30,178	$	40,072

Current maturities of long-term debt	$	11,550	$	19,666
Current liabilities		16,900		10,995
Deferred credits — Other		—		5,205

	$	28,450	$	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 nine months ended September 30 follows. This summary is based on a September 30 measurement date (dollars in thousands):


	Three Months Ended September 30,												Nine Months Ended September 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		$	13,491		$	11,405		$	2,338		$	1,841
Interest cost		7,568			7,350			2,382			2,221			22,705			22,050			7,146			6,662
Expected return on plan assets		(7,658	)		(5,284	)		(1,034	)		(965	)		(22,974	)		(15,851	)		(3,101	)		(2,895	)
Amortization of prior service cost		428			492			16			16			1,285			1,475			47			47
Amortization of Transition Obligation		—			—			242			242			—			—			727			727
Amortization of net loss		2,243			2,522			1,157			717			6,728			7,565			3,470			2,150

Net periodic benefit cost	$	7,078		$	8,882		$	3,542		$	2,845		$	21,235		$	26,644		$	10,627		$	8,532

In the third quarter of 2004, SPR made a contribution to the pension plan in the amount of $35.5 million, as was estimated and 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. At the present time there is no change expected to the 2004 estimated employer contribution amount of $0.2 million which was previously disclosed for other postretirement benefits.

In May 2004, the FASB issued final guidance on FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” and SPR elected to prospectively adopt the provisions set forth in this pronouncement. Accordingly, SPR is required to record the reduction to expense beginning with the third quarter of 2004. The effect of the subsidy on SPR’s costs for Other Postretirement Benefits was actuarially determined to be an annual reduction of $0.8 million for 2004. However, as a result of prospective application of the pronouncement, one quarter of the total reduction ($0.2 million), was recorded at September 30, 2004, and another $0.2 million will be recorded at December 31, 2004. Additional annual savings as a result of the revisions to Medicare will be reflected through future annual valuations.

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

Forward-Looking Statements and Risk Factors

The information in thisForm 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 Enron Power Marketing, Inc. (“Enron”) for amounts allegedly due under terminated purchase power contracts;

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

(6)		whether the Utilities will be able to complete construction of their current generation and transmission projects in a timely manner, including NPC’s completion of the Lenzie station;

(7)		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;

(8)		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;

(9)		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;

(10)		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;

(11)		whether SPR, NPC and SPPC will meet all requirements of Section 404 of the Sarbanes-Oxley Act to ensure that management can provide a positive assertion of the effectiveness of SPR, NPC and SPPC’s internal control over financial reporting as of December 31, 2004;

(12)		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;

(13)		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;

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

(15)		the loss of any significant customers;

(16)		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;

(17)		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;

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

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

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

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

(22)		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 the 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 SPR’s ability to service its debt in jeopardy. In August 2003, a judgment in excess of $300 million against the Utilities was entered by a U.S. Bankruptcy Court in favor of Enron for contracts that Enron 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. The uncertainties, as documented in the 2003 10-K, included:

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

•		whether SPR and the Utilities would 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 would 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 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 responded aggressively and with positive result with respect to each of the issues. The Utilities appealed the Enron Bankruptcy Court’s decision to the U.S. District Court and successfully obtained a reversal and remand of the Bankruptcy Court’s decision, as discussed below. The Utilities were granted a hearing by the Federal Energy Regulatory Commission (FERC) in response to their petition claiming that Enron wrongfully terminated the contracts and therefore should not be paid. The Utilities also reached agreement with Enron that will not require either NPC or SPPC to provide any additional collateral, beyond the $60 million in cash and the Utilities’ General and Refunding Mortgage Bonds that have been deposited in escrow, through the pendancy of all remands and appeals of the Bankruptcy Court’s decision. Through consent of bondholders and a modification of PUCN restrictions, SPR once again has the ability to service SPR debt through dividends from NPC. SPR and the Utilities refinanced near-term debt maturities at favorable rates and terms, and secured liquidity facilities that will be available for several years. New power and fuel procurement practices, along with risk control policies and practices were recognized in recent PUCN decisions, in which NPC recovered virtually all and SPPC recovered all of their fuel and power costs. The Utilities announced a strategy to begin reducing their exposure to volatile swings in power prices through, for NPC, the acquisition of a partially constructed power plant that is expected to be placed into service in early 2006 and, for SPPC, the building of a new power plant that, if approved by the PUCN, will be in service by the summer of 2008.

Although 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 November 5, 2004, and later 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.

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

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

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

The District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The District Court rejected Enron’s cross-appeal seeking a 12% per year post-judgment interest rate instead of the 1.21% interest rate ordered by the Bankruptcy Court. The Utilities do not know whether Enron will appeal this portion of the District Court’s decision or the timing of any such appeal. The District Court decision also provides that Enron may, if proper, renew its motion to enjoin the proceedings currently before the FERC addressing Enron’s termination of its power supply contracts with NPC and SPPC. The Utilities continue to assess the impact of the District Court’s decision.

On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. Hearings were scheduled to begin on October 25, 2004 and an initial decision was expected from the FERC by December 31, 2004. However, on October 12, 2004, after learning on the same day that Enron had not produced and would not be able to produce by the scheduled October 25th hearing date approximately 900,000 documents and approximately 84,000 e-mails that are potentially responsive to the Utilities’ document requests, the Utilities filed an emergency motion to delay the hearings to ensure that hearings will be based on a full record after adequate time for discovery. All parties in the dispute supported the delay. As a result, on October 13, 2004, the Chief Administrative Law Judge at the FERC suspended the prior deadline for an initial decision in the matter from December 31, 2004 to February 14, 2005. The hearings have been rescheduled for the week of December 13, 2004. The Utilities are unable to predict the outcome of this FERC proceeding or whether FERC’s decision will affect the Bankruptcy Court’s reconsideration of this matter and any subsequent appeals of the Judgment or related matters and cases.

At September 30, 2004, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” are approximately $273 million and $106 million of charges, respectively, for terminated power supply contracts, including Enron, and associated interest. Correspondingly, pursuant to the deferred energy accounting provisions of AB 369, included in NPC and SPPC deferred energy balances as of September 30, 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 $112 million, respectively, of which $160 million and $66 million, respectively, were incurred through September 30, 2004, and capital requirements for construction costs in 2005 will be approximately $618 million and $170 million, respectively. The Utilities expect to finance these costs with internally generated funds, including the recovery of deferred energy, and with new secured debt. Through October 31, 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. NPC has also put into place credit facilities to support the purchase of the Chuck Lenzie Generating Station and its associated 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.

•		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 8 3/4% 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 $130 million of its 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 $100 million 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.

•		On October 8, 2004, NPC entered into a $250 million Credit Agreement, under which it borrowed $150 million to pay part of the $182 million purchase price for the Chuck Lenzie Generating Station (formerly known as Moapa Energy

Facility, described later in this section). On October 22, 2004, NPC amended and restated this Credit Agreement to increase the size of the credit facility to $350 million and simultaneously terminated its prior $100 million Credit Agreement. Borrowings under this facility may be used to fund construction costs for the Chuck Lenzie Generating Station or for NPC’s general corporate purposes.

•

On October 22, 2004, SPPC entered into a $75 million Credit Agreement, which replaced its prior $50 million Credit Agreement. Borrowings under this Credit Agreement may be used for general corporate purpose.

The above financings significantly alleviate the Utilities’ short term financing concerns.

SPR expects to meet its 2004 and 2005 debt service obligations 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

NPC’s General Rate Case

NPC filed its biennial General Rate Case on October 1, 2003, as required by law. NPC requested a $142 million increase in the annual revenue requirement for general rates.

•		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.

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. 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. On October 16, 2004, NPC filed a petition requesting that delayed implementation and ordered or anticipated changes be made at the same time on April 1, 2005 in order to stabilize rates and reduce the number of rate changes.

SPPC’s 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 PUCN 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 have been 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 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 nor can SPPC predict the outcome of its decision.

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 an adverse effect on the Utilities’ future results of operations, could cause additional downgrades of their securities by the rating agencies and make it more difficult to finance operations and to buy fuel and purchased power from third parties.

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 requested PUCN authorization to acquire a partially completed power plant, the Chuck Lenzie Generating Station (“Facility”), from Duke Energy (“Duke”) for $182 million. The amendment requested approval to substitute the 1200 MW Facility, for the previously approved Harry Allen

520 MW combined cycle generator. The Facility consists of four natural gas-fired combustion turbines, two steam turbines and four heat-recovery steam generators operating in combined cycle mode.

On September 21, 2004, the PUCN granted NPC’s request for a critical facility designation and allowed for a 2% enhancement of the authorized ROE to be applied to the rate base associated with the Facility construction costs expended after acquisition. The PUCN also granted NPC’s request for $500 million in long-term debt authority. The order allows for up to an additional 1% enhanced ROE if the two generator units are brought on line early and the gradual elimination of the enhanced ROE if completion is delayed. The order allows NPC to include the plant investments during construction in rate base when NPC files its regularly scheduled general rate cases, which permits NPC to earn a return during construction. The PUCN also granted NPC’s request to establish regulatory asset accounts to prevent the erosion of earnings, which otherwise would occur due to regulatory lag. The regulatory asset account will capture the depreciation expense and return on rate base between the time the plant is placed in service and when the plant costs are included in rates.

On October 13, 2004, following the PUCN decision, NPC completed the acquisition of the Facility from Duke. Completion of Unit 1 generator is expected no later than March 31, 2006, and June 30, 2006 is the targeted completion date for Unit 2.

Total costs to acquire and complete construction of the Facility are estimated at $558 million, which includes $182 million paid to Duke for the Facility in its current state of completion, $5 million for partial reimbursement of prepaid property taxes and payments made by Duke to the regional required system upgrade trust account, AFUDC, costs for distribution and transmission facilities and costs expected to be incurred under a construction contract with Fluor Enterprises, Inc. The purchase price was paid through a combination of available cash and borrowings under NPC’s revolving credit facility established on October 8, 2004 (discussed earlier). Before the end of 2004, NPC expects to enter into long-term financing in the amount of approximately $250 million. The proceeds from the long-term financing will be used to pay down outstanding amounts under the revolving credit facility, to pay fees, costs and expenses in connection with the purchase and construction of the Facility and for general corporate purposes. In the event that NPC cannot complete this long-term financing, NPC may be required in the future to delay the construction of the Facility.

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

Business Strategies

Enron Litigation

The Utilities have filed a motion seeking clarification from the District Court on various issues not addressed in the District Court’s decision including among other issues the constitutional power of a bankruptcy court to enter a final judgment in a “non core matter”, and whether the Bankruptcy Court had properly determined the interest rate applicable to pre-judgment interest. If the Utilities do not prevail on the remand of the case to the Bankruptcy Court, they may seek a further appeal. Enforcement of any judgment that might be obtained by Enron against the Utilities would likely be stayed pursuant to the parties’ stipulation and agreement (discussed above); however, there can be no assurances a court hearing the case or an appeal of the case would accept the collateral arrangement without modification in the event that a subsequent judgment were entered against the Utilities.

Management believes that the Remarketing Agreement will facilitate the successful remarketing of the Bonds to satisfy the Utilities’ payment obligations in the event that the Utilities had to pay a judgment in favor of Enron.

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 claims and/or judgments against the Utilities. 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 Utilities are ultimately required to pay Enron for liquidated damages associated with the terminated power supply contracts, the Utilities would pursue recovery of such amounts through their 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 claims against the Utilities 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

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. In addition, management believes that NPC’s $350 million revolving credit agreement and NPC’s $250 million long-term financing, expected to be completed before the end of 2004 or early 2005, should provide NPC with sufficient liquidity to complete the construction of its recently-acquired Chuck Lenzie Generating Station. In the event that NPC is unable to complete its contemplated $250 million long-term financing, NPC may be required to delay the construction of portions of the Chuck Lenzie Generating Station.

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. In July 2004, SPPC filed its plan including, among other things, a new 500 MW plant to be built by the summer of 2008.

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 charges that would offset in whole or in part SPR’s earnings 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 for the nine months ended September 30, 2004, compared favorably to the same period in 2003, primarily due to an unrealized loss recorded in September 2003 of approximately $46.1 million on the derivative associated with the issuance of $300 million of convertible debt. The improved 2004 operating results were partially offset by charges recognized during 2004 that included an impairment of goodwill of approximately $11.7 million and higher interest costs. The Holding Company recognized charges of approximately $23.7 million during 2004 for tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8¾% Senior Unsecured Notes due 2005. See Note 6 of the Condensed Notes to Consolidated Financial Statements, Long-Term Debt.

Sierra Pacific Resources (Consolidated)

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

During the three months ended September 30, 2004, SPR recognized income applicable to common stock of approximately $90.7 million compared to approximately $107.8 million of income applicable to common stock for the same period in 2003. The decrease in SPR’s consolidated income during 2004 compared to 2003 was primarily due to an unrealized gain of approximately $61.5 million on the derivative instrument associated with the issuance of $300 million of convertible debt recorded in the third quarter of 2003.

Partially offsetting the decrease in income applicable to common stock during the third quarter of 2004 compared to the same period in 2003 were interest charges recognized in September 2003 of approximately $28 million and $12 million by NPC and SPPC, respectively. The interest charges were recognized as a result of the September 26, 2003, Bankruptcy Court judgment in favor of Enron for terminated power supply agreements with the Utilities. Although the judgment has been vacated by the U.S. District Court for the Southern District of New York, the interest charge will not be reversed unless a final decision or other determination is eventually rendered in favor of the Utilities.

During the nine months ended September 30, 2004, SPR recognized income applicable to common stock of approximately $1.3 million compared to an approximate $120.7 million loss applicable to common stock for the same period in 2003. SPR’s improved operating results during 2004 compared to 2003 was primarily due to the following items (before income taxes):

•		an unrealized loss of approximately $46.1 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 $46.0 million and $45.0 million by NPC and SPPC, respectively, recorded in 2003;

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

•		interest charges recognized in September 2003 in connection with the Enron judgment of approximately $28 million and $12 million by NPC and SPPC, respectively.

		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;

•		charges 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 8¾% 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 nine months ended September 30, 2004. For the nine months ended September 30, 2004, NPC paid common stock dividends of $39.6 million to its parent, SPR. For the nine months ended September 30, 2004, SPPC declared and paid $2.925 million in dividends to holders of its preferred stock. On October 28, 2004, NPC declared a common stock dividend of $5.4 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 nine months ended September 30, 2004 compared to the same period in 2003, as a result of a decrease in cash from operating activities, offset by a decrease in cash used for investing activities and an increase in cash from financing 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. Increased collection efforts, initiated in 2003, decreased NPC’s and SPPC’s accounts receivable balance as of December 2003 compared to December 2002.

Cash flows from financing activities was higher for the nine months ended September 30, 2004 compared to the same period in 2003, primarily as a result of the issuance of $335 million in new debt issued by SPR, which was used to redeem $300 million of SPR’s notes due in 2005. Cash used in investing activities decreased primarily as a result of a decrease in construction activity in 2004.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Dividends from Subsidiaries

Dividend Restrictions Applicable to Nevada Power Company

•

•		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.

•

The following notes, bonds and credit agreement limit the amount of payments in respect of common stock that NPC may make to SPR:

•		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 6½% General and Refunding Mortgage Notes, Series I, due 2012, which were issued on April 7, 2004,

•		NPC’s Revolving Credit Agreement, which was established on October 8, 2004 in connection with the purchase of the Chuck Lenzie Generating Station, and amended and restated on October 22, 2004.

•		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, the Series H Bond and the NPC 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 NPC 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 Agreement, 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.

•

Dividend Restrictions Applicable to Sierra Pacific Power Company

•

The following notes, bonds and credit facilities limit the amount of payments in respect of common stock that SPPC may make to SPR:

•		SPPC’s Revolving Credit Agreement, which was established on October 22, 2004,

•		SPPC’s 6¼% General and Refunding Mortgage Notes, Series H, due 2012, which were issued on April 16, 2004,

•		SPPC’s General and Refunding Mortgage Bond, Series E, which was issued on December 4, 2003.

•		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 SPPC 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.

•

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

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

Assuming that NPC and SPPC meet the requirements to pay dividends under the Federal Power Act and that any dividends paid to SPR are for SPR’s debt service obligations and current operating expenses, the most restrictive of the dividend restrictions applicable to the Utilities individually can be found for NPC, in NPC’s Series E Notes and, for SPPC, in SPPC’s Series H Notes, Series E Bond and its Revolving Credit Agreement (which was terminated on October 22, 2004), and Lenzie related Revolving Credit Facility. 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.

Financing Transactions (SPR – Holding Company)

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 8 3/4% 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:

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.

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;

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

•		The terms of NPC’s Series E Notes, Series G Notes, Series I Notes, and 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 each series of Notes, the Bonds to require NPC to redeem their series of Notes or the Bonds 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;

•		NPC’s $350 million Credit Agreement provides for an event of default if NPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million. Upon an event of default, the Administrative Agent under the NPC Credit Agreement may, upon request of more than 50% of the lenders under the Credit Agreement, declare all amounts due under the Credit Agreement immediately due and payable. Since NPC’s obligations under the Credit Agreement are secured by its General and Refunding Mortgage Bond, if NPC fails to repay all amounts due upon an acceleration of the Credit Agreement within three business days, such failure will be deemed a default in the

		payment of principal and will trigger an event of default under NPC’s General and Refunding Mortgage Indenture that would be applicable to all securities issued under NPC’s General and Refunding Mortgage Indenture;

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

•		The terms of SPPC’s Series H Notes and Series E 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 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 and the Series E Bond to require SPPC to redeem their series of Notes or Bonds, 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; and

•		SPPC’s $75 million Credit Agreement provides for an event of default if SPPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million. Upon an event of default, the Administrative Agent under the SPPC Credit Agreement may, upon request of more than 50% of the lenders under the Credit Agreement, declare all amounts due under the Credit Agreement immediately due and payable. Since SPPC’s obligations under the Credit Agreement are secured by its General and Refunding Mortgage Bond, if SPPC fails to repay all amounts due upon an acceleration of the Credit Agreement within three business days, such failure will be deemed a default in the payment of principal and will trigger an event of default under SPPC’s General and Refunding Mortgage Indenture that would be applicable to all securities issued under SPPC’s General and Refunding Mortgage Indenture.

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 $350 million 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 secured 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.

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 September 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 $75 million 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 and Series H Notes were issued under SPPC’s General and Refunding Mortgage Indenture and SPPC’s Revolving Credit Agreement is secured 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.

Financial Covenants

Nevada Power Company and Sierra Pacific Power Company

Each of NPC’s $350 million Revolving Credit Agreement, as amended and restated on October 22, 2004, and SPPC’s $75 million Revolving Credit Agreement dated October 22, 2004, contains two financial maintenance covenants. The first requires that the Utility maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that the Utility maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.

Due to a negative pledge obligation in SPPC’s $92 million General and Refunding Mortgage Bond, Series E, SPPC expects to amend its Series E Bond to include these two financial maintenance covenants. SPPC’s Series E Bond, which is currently held by an escrow agent, was issued to secure the Enron Judgment. (See Note 9 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies for a discussion of the Enron Judgment.) Although the Judgment was vacated in a decision handed down on October 10, 2004 by the U.S. District Court for the Southern District of New York, the Series E Bond will continue to remain in escrow through the pendancy of all remands and appeals pursuant to a stipulation and agreement previously entered into among NPC, SPPC and Enron.

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 71/4% 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 September 30, 2004, SPR, NPC, SPPC, and their subsidiaries had approximately $3.9 billion of debt and other obligations outstanding, consisting of approximately $2.0 billion of debt at NPC, approximately $1.0 billion of debt at SPPC and approximately $0.9 billion of debt at the holding company and other subsidiaries. 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 nine months ended September 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 8¾% Notes due 2005.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three-months ended September 30, 2004, NPC recognized net income of approximately $86.2 million compared to net income of approximately $62.5 million for the same period in 2003. During the nine months ended September 30, 2004, NPC recognized net income of approximately $84.4 million compared to net income of approximately $25.1 million for the same period in 2003. For the nine months ended September 30, 2004, NPC declared and paid common stock dividends totaling $39.6 million to its parent, SPR. On October 28, 2004, NPC declared a common stock dividend of $5.4 million, payable November 14, 2004.

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


	Three Months								Nine Months
	Ended September 30,								Ended September 30,
						Change from							Change from
	2004		2003			Prior Year %			2004		2003		Prior Year %
Operating Revenues:
Electric	$	633,609	$	639,661			-0.9	%	$	1,410,067	$	1,396,825		0.9	%
Energy Costs:
Purchased power		300,290		333,069			-9.8	%		619,329		657,455		-5.8	%
Fuel for power generation		67,216		95,453			-29.6	%		176,883		209,900		-15.7	%
Deferred of energy costs-disallowed		—		—			N/A			1,586		45,964		-96.5	%
Deferral of energy costs-electric-net		9,496		(35,967	)		-126.4	%		91,622		48,260		89.9	%

		377,002		392,555			-4.0	%		889,420		961,579		-7.5	%

Gross Margin	$	256,607	$	247,106			3.8	%	$	520,647	$	435,246		19.6	%

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							Nine Months
	Ended September 30,				Change from			Ended September 30,				Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Electric Operating Revenues:
Residential	$	301,651	$	266,585		13.2	%	$	620,782	$	555,514		11.7	%
Commercial		110,501		103,638		6.6	%		283,566		264,861		7.1	%
Industrial		184,901		193,601		-4.5	%		415,228		414,177		0.3	%

Retail revenues		597,053		563,824		5.9	%		1,319,576		1,234,552		6.9	%
Other		36,556		75,837		-51.8	%		90,491		162,273		-44.2	%

Total Revenues	$	633,609	$	639,661		-0.9	%	$	1,410,067	$	1,396,825		0.9	%

Retail sales in thousands of megawatt-hours (MWh)		6,155		6,166		-0.2	%		14,644		14,053		4.2	%
Average retail revenue per MWh	$	97.00	$	91.44		6.1	%	$	90.11	$	87.85		2.6	%

NPC Retail revenues were higher for the three months ended September 30, 2004, when compared to prior year, due to customer growth and higher rates. The number of residential, commercial, and industrial customers increased by 4.7%, 5.6%, and 2.5%, respectively. Higher rates were the results from NPC’s General and Deferred Energy Rate Cases effective April 01, 2004. Partially offsetting this increase was lower electric usage as a result of cooler summer weather.

Retail revenues were higher for the nine months ended September 30, 2004, compared to the same period in the prior year due to increases in customer growth, warmer weather, and higher rates. The number of residential, commercial, and industrial customers increased by 5.0%, 5.4%, and 4.8%, respectively. Higher rates were the results from NPC’s General and Deferred Energy Rate Cases effective April 01, 2004. This increase in revenues was partially offset by decreases in retail rates in 2004 that were effective May 19, 2003, as a result of NPC’s Deferred Energy Rate Case (refer to Regulatory Proceedings (Utilities), later). Based on NPC’s customer growth forecast, the numbers of electric customers in all classes are expected to continue to grow for the remainder of the year. Several new casino expansions and hospitals in the Clark County area are expected to have a positive impact on retail revenues in the coming months.

Electric Operating Revenues – Other decreased for the three and nine months ended September 30, 2004, compared to the same periods in 2003, primarily due to a decrease in the sales volumes of wholesale electric power to other utilities associated with risk management activities and a refund of $5.9 million to transmission customers as a result of FERC’s approval of a tariff agreement on July 8, 2004 (refer to Regulatory Proceedings (Utilities), later). Risk management activities include transactions entered into for hedging purposes and to optimize purchase power costs. See NPC’s Annual Report in Form 10-K for the year ended December 31, 2003, 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							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Purchased Power:	$	300,290	$	333,069		-9.8	%	$	619,329	$	657,455		-5.8	%
Purchased Power in thousand of MWhs		4,561		4,763		-4.2	%		10,059		10,293		-2.3	%
Average cost per MWh of Purchased Power	$	65.84	$	69.93		-5.8	%	$	61.57	$	63.87		-3.6	%

NPC’s purchased power costs were lower for both the three months and nine months ended September 30, 2004, compared to the same periods in 2003 primarily due to lower volumes purchased. Although retail MWh sales increased, this was offset by a significant decrease in wholesale sales associated with risk management activities, as discussed in Electric Operating Revenues-Other, which resulted in a reduction of purchased power. Also, the average cost per MWh of purchased power decreased for the three months and nine months ended September 30, 2004, primarily due to the recognition of additional provisions for terminated purchased power contracts that were recorded in the second and third quarter of 2003. Also, contributing to a lesser extent to the lower average cost per MWh, was a decrease in the cost of Short-Term energy contracts.

Due to an increase in gas costs, NPC anticipates an increase in the cost of Purchased Power over the next three months.

Fuel For Power Generation


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change							Change
	2004		2003		from Prior Year %			2004		2003		from Prior Year %
Fuel for Power Generation	$	67,216	$	95,453		-29.6	%	$	176,883	$	209,900		-15.7	%
Thousands of MWhs generated		2,362		2,796		-15.5	%		6,295		6,715		-6.3	%
Average cost per MWh of Generated Power	$	28.46	$	34.14		-16.6	%	$	28.10	$	31.26		-10.1	%

Fuel for generation for the three and nine months ended September 30, 2004 decreased compared to the same periods in the prior year due to lower volumes and lower average cost per unit of generated electricity. NPC satisfied more of its native load requirements through purchase power rather than generation. The average unit cost per megawatt hour of generated power was lower because of lower coal and natural gas costs in 2004 compared to 2003. NPC anticipates gas prices to increase over the remainder of 2004.

Deferred Energy Costs


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
						Change from						Change from
	2004		2003			Prior Year %		2004		2003		Prior Year %
Deferred energy costs disallowed	$	—	$	—			N/A	$	1,586	$	45,964		N/A
Deferred energy costs — net	$	9,496	$	(35,967	)		N/A	$	91,622	$	48,260		89.9	%

Deferred energy costs disallowed for the nine months ended September 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 Proceedings (Utilities), NPC’s 2003 Deferred Energy Rate Case. Deferred energy costs disallowed for the nine months ended September 30, 2003, reflects the PUCN disallowance of approximately $46 million in May 2003, of deferred energy costs incurred during the twelve months ended November 2002.

Deferred energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy costs – net also include the current amortization of fuel and purchased power costs previously deferred.

Deferred energy costs – net increased for the three months ended September 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 the same period in 2003. Deferred energy costs – net also increased for the nine months ended September 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 and 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.

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

Allowance For Funds Used During Construction (AFUDC)


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from Prior							Change from Prior
	2004		2003		Year %			2004		2003		Year %
Allowance for other funds used during construction	$	487	$	281		73.3	%	$	1,769	$	1,922		-8.0	%
Allowance for borrowed funds used during construction	$	759	$	573		32.5	%	$	2,465	$	2,149		14.7	%

	$	1,246	$	854		45.9	%	$	4,234	$	4,071		4.0	%

AFUDC was higher for the three and nine month periods ended September 2004, compared to the same periods in 2003 due to an increase in the AFUDC rate from 8.37% to 9.03%, which was effective April 2004 as a result of NPC’s General Rate Case. The increase for the nine month period ended September 2004 was partially offset by a decrease in the Construction Work in Progress (CWIP) balance on which AFUDC is calculated. The decrease in CWIP was primarily due to Transmission and Distribution (Centennial and Crystal) projects which were placed in service in 2004.

Other (Income) and Expenses


	Three Months									Nine Months
	Ended September 30,									Ended September 30,
							Change from Prior									Change from Prior
	2004			2003			Year %			2004			2003			Year %
Other operating expense	$	45,515		$	44,749			1.7	%	$	136,150		$	136,964			-0.6	%
Maintenance expense	$	10,834		$	9,203			17.7	%	$	47,580		$	38,390			23.9	%
Depreciation and amortization	$	29,900		$	28,474			5.0	%	$	88,630		$	81,095			9.3	%
Income tax expense	$	43,346		$	30,556			41.9	%	$	37,232		$	3,734			N/A
Interest charges on long-term debt	$	37,736		$	37,365			1.0	%	$	112,570		$	104,215			8.0	%
Interest charges-other	$	3,824		$	34,171			-88.8	%	$	13,652		$	46,165			-70.4	%
Interest accrued on deferred energy	$	(5,142	)	$	(5,952	)		-13.6	%	$	(15,335	)	$	(16,896	)		-9.2	%
Disallowed merger costs	$	—		$	—			N/A		$	3,961		$	—			N/A
Other income	$	(5,335	)	$	(4,042	)		32.0	%	$	(16,464	)	$	(11,633	)		41.5	%
Other expense	$	1,698		$	1,441			17.8	%	$	4,626		$	4,491			3.0	%
Income taxes — other income and expense	$	3,109		$	3,084			0.8	%	$	8,154		$	8,277			-1.5	%

Other operating expense for the three and nine month periods ended September 30, 2004 were comparable to the same periods in 2003.

Maintenance costs for the three and nine month periods ended September 30, 2004 increased compared to the prior year due to the timing of scheduled and unscheduled plant maintenance at the Clark Station, Sunrise and Reid Gardner generating facilities.

Depreciation and amortization expense increased for the three and nine month periods ended September 30, 2004, compared to the same periods in 2003, as a result of an increase in plant-in-service. The three month increase was 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 higher income tax expense for the three and nine months ended September 30, 2004, compared to the same periods during 2003. These increases are primarily a result of higher pre-tax operating income recognized during these

periods of 2004 compared to the same period in 2003. During the first nine months of 2004, NPC recognized higher operating revenues and a decrease in fuel and purchased power expenses. Also contributing to the year to date change from 2004 to 2003 was the recognition in the second quarter of 2003 of tax benefits resulting from the partial resolution of an Internal Revenue Service audit.

Interest charges on Long-Term Debt for the nine months ended September 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%, 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 three and nine months ended September 30, 2004, were significantly lower than the comparable periods in 2003 due to the recording in September 2003 of approximately $28 million interest expense related to the Enron terminated contract liability. Additionally, NPC recognized lower interest charges related to the accounts receivable facility, which was terminated in May 2004, during the three and nine months ended September 30, 2004, when compared to the same periods in 2003.

Interest accrued on deferred energy costs for the three and nine months ended September 30, 2004, decreased from the comparable periods in 2003 due to lower deferred fuel and purchased power balances. (Refer to Regulatory Proceedings (Utilities) for further discussion of deferred energy accounting issues).

Disallowed merger costs expense for the nine months ended September 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 nine months ended September 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 during the third quarter of 2003, reduced slightly by lower interest income in 2004. Income from the sale of utility property is recognized in revenue over a three year period consistent with the accounting treatment directed by the PUCN. 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 for the three and nine month periods ending September 30, 2004 was comparable to the same period in the prior year.

ANALYSIS OF CASH FLOWS

NPC’s cash flows were less during the nine months ended September 30, 2004, compared to the same period in 2003 resulting primarily from financing activities. Cash from operating activities during the nine months in 2004 were mostly unchanged compared to the same period in 2003. There was increased cash in 2004 as a result of collecting higher amounts in rates for deferred energy balances than the amounts being currently deferred, offset by the cash payment of $50 million to the Enron escrow account. Increased collection efforts, initiated in 2003, significantly decreased NPC’s accounts receivable balance as of December 2003 compared to December 2002, resulting in a greater change in 2004 when compared to 2003. The decrease in cash from financing activities is primarily due to a $40 million dividend paid to SPR.

LIQUIDITY AND CAPITAL RESOURCES

NPC had cash and cash equivalents of approximately $108 million at September 30, 2004.

NPC anticipates capital requirements for construction costs in 2004 will be approximately $473 million, of which $160 million has been spent through September 30, 2004. NPC’s anticipated capital requirements for construction during 2005 are approximately $618 million. Total construction costs for both years include the recently announced Chuck Lenzie Generating Station discussed below, which NPC expects to finance with internally generated funds, including the recovery of deferred energy, existing credit facility and long-term debt issuance. NPC acquired the facility for approximately $182 million in October 2004. Through October 31, 2004, NPC had issued and/or refinanced maturing debt and its revolving credit facility to support its operations, including purchasing power and supporting construction costs.

Chuck Lenzie Generating Station 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 north of Las Vegas, “Chuck Lenzie Generating Station.” 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 was approved by the PUCN on September 17, 2004 and closed on October 13, 2004. NPC expects to finance this purchase and complete construction with a combination of the issuance of secured debt and internally generated cash.

The financing plan associated with the purchase and construction, and as outlined in the Lenzie Financing Application filed with the PUCN, consists of the following steps:

•		NPC financed the acquisition with a $250 million revolving credit facility that was put in place on October 8, 2004 and increased to $350 million on October 22, 2004. NPC borrowed $150 million under this revolving credit facility to fund a portion of the $182 million acquisition price. This facility will also be used to fund some of the initial construction expenditures.

•		Before the end of the current year or early next year, NPC expects to issue a General and Refunding Mortgage Notes in the amount of $250 million. The proceeds from this financing would then be used to pay down the outstanding balance of the revolving credit facility and would also be used to fund a portion of the construction of the Lenzie facility.

•		The $350 million revolving credit facility, in conjunction with available internally generated funds, would be used to complete the construction of the Lenzie facility as well as the construction of the Harry Allen combustion turbine.

•		The combination of the $250 million General and Refunding Mortgage Notes expected to be sold by the end of this year or early next year plus $250 million of the $350 million revolving credit facility would equal the $500 million in long-term debt authority requested in the Lenzie Financing Application.

•		We expect that by 2007, the secured revolving credit facility will be paid off with operating cash flow.

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).

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 September 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 September 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 and on plant accounting records as of September 30, 2004 (which do not include additions to plant associated with the acquisition of the Lenzie Generating Station), as of October 31, 2004, NPC had the capacity to issue approximately $508 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 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 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.

Chuck Lenzie Generating Station Related Revolving Credit Facility

credit facility to $350 million, concurrently with its termination of its $100 million Credit Facility, which was established on May 4, 2004. The new revolving credit facility, which is secured by NPC’s $350 million General and Refunding Mortgage Bond, Series K, will expire October 8, 2007. The rate for outstanding loans and/or letters of credit under revolving credit facility will be at either an alternate base rate or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s alternate base rate margin is 1.00% and its Eurodollar margin is 2.00%.

The Credit Agreement, similar to NPC’s Series E Notes, Series G Notes, Series H Bond and Series I Notes, 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 Credit Agreement also contains a restriction on NPC’s ability to incur additional indebtedness which is similar to the restriction discussed above for NPC’s Series I Notes.

$100 million Revolving Credit Facility

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 September 30, 2004, provides for an event of default if a matured event of default under NPC’s First Mortgage Indenture occurs;

•		The terms of NPC’s Series E Notes, Series G Notes, Series I Notes, and 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, and Series H Bond to require NPC to redeem their series of Notes or the Bonds 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; and

•		NPC’s $350 million Credit Agreement provides for an event of default if NPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million. Upon an event of default, the Administrative Agent under the NPC Credit Agreement may, upon request of more than 50% of the lenders under the Credit Agreement, declare all amounts due under the Credit Agreement immediately due and payable. Since NPC’s obligations under the Credit Agreement are secured by its General and Refunding Mortgage Bond, if NPC fails to repay all amounts due upon an acceleration of the Credit Agreement within three business days, such failure will be deemed a default in the payment of principal and will trigger an event of default under NPC’s General and Refunding Mortgage Indenture that would be applicable to all securities issued under NPC’s General and Refunding Mortgage Indenture.

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 $350 million 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 secured 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.

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.

Financial Covenants

NPC’s $350 million Revolving Credit Agreement, as amended and restated on October 22, 2004, contains two financial maintenance covenants. The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.

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 expects to spend up to approximately $553 million (excluding AFUDC) for the construction and acquisition of generation facilities including the Chuck Lenzie Generating Station ($506 million) and the Harry Allen Combustion Turbine ($47 million) and approximately $135 million of additional expenditures for the construction of the Centennial Transmission Project prior to the summer of 2007.

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 Chuck Lenzie Generating Station from Duke Energy, a 2nd Amendment to the NPC Integrated Resource Plan and an associated $500 million financing application. The PUCN approved the application on September 17, 2004. Please refer to the Chuck Lenzie Generating Station Financing Plan section for a further discussion of this financing plan.

During the nine months ended September 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, other than the April 2004 issuance of NPC’s $130 million 6.5% General and Refunding Mortgage Notes due April 15, 2012 and the May 2004 establishment of a $100 million Revolving Credit Facility, which was terminated on October 22, 2004. On October 8, 2004, NPC established a $250 million Revolving Credit Facility in connection with the purchase and construction of the Chuck Lenzie Generation Station. On October 22, 2004, NPC amended this Revolving Credit Facility to increase the size of the Revolving Credit Facility to $350 million.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended September 30, 2004, SPPC recognized net income applicable to common stock of approximately $20.8 million compared to a loss applicable to common stock of $1.3 million for the same period in 2003. During the nine months ended September 30, 2004, SPPC incurred a net loss applicable to common stock of approximately $5.7 million compared to $27.2 million for the same period in 2003. For the nine months ended September 30, 2004 SPPC

declared and paid $2.925 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. On October 28, 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									Nine Months
	Ended September 30,									Ended September 30,
							Change from								Change from
	2004			2003			Prior Year %			2004		2003			Prior Year %
Operating Revenues:
Electric	$	253,615		$	250,476			1.3	%	$	657,881	$	660,956			-0.5	%
Gas		16,387			13,931			17.6	%		97,742		114,421			-14.6	%

	$	270,002		$	264,407			2.1	%	$	755,623	$	775,377			-2.5	%

Energy Costs:
Purchased Power	$	92,481		$	125,337			-26.2	%	$	230,577	$	288,692			-20.1	%
Fuel for power generation		59,494			62,412			-4.7	%		166,715		143,144			16.5	%
Deferred energy costs disallowed		—			—			N/A			—		45,000			-100.0	%
Deferral of energy costs-electric-net		(3,269	)		(22,174	)		-85.3	%		1,436		(3,531	)		-140.7	%
Gas purchased for resale		11,322			7,133			58.7	%		73,721		77,332			-4.7	%
Deferral of energy costs-gas-net		297			2,200			-86.5	%		266		14,023			-98.1	%

		160,325			174,908			-8.3	%		472,715		564,660			-16.3	%

Energy Costs by Segment:
Electric	$	148,706		$	165,575			-10.2	%	$	398,728	$	473,305			-15.8	%
Gas		11,619			9,333			24.5	%		73,987		91,355			-19.0	%

	$	160,325		$	174,908			-8.3	%	$	472,715	$	564,660			-16.3	%

Gross Margin by Segment:
Electric	$	104,909		$	84,901			23.6	%	$	259,153	$	187,651			38.1	%
Gas		4,768			4,598			3.7	%		23,755		23,066			3.0	%

	$	109,677		$	89,499			22.5	%	$	282,908	$	210,717			34.3	%
					��

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							Nine Months
	Ended September 30,							Ended September 30,
					Change from Prior							Change from Prior
	2004		2003		year %			2004		2003		year %
Electric Operating Revenues:
Residential	$	69,367	$	60,305		15.0	%	$	182,003	$	172,565		5.5	%
Commercial		85,808		76,881		11.6	%		220,717		208,746		5.7	%
Industrial		82,407		75,752		8.8	%		219,531		210,680		4.2	%

Retail revenues		237,582		212,938		11.6	%		622,251		591,991		5.1	%
Other⁽¹⁾		16,033		37,538		-57.3	%		35,630		68,965		-48.3	%

Total Revenues	$	253,615	$	250,476		1.3	%	$	657,881	$	660,956		-0.5	%

Retail sales in thousands of MWh		2,438		2,374		2.7	%		6,843		6,674		2.5	%
Average retail revenue per MWh	$	97.45	$	89.70		8.6	%	$	90.93	$	88.70		2.5	%

(1)

Primarily Economy Energy and Firm Wholesale Sales, as discussed below

SPPC’s retail revenues increased for the three months and nine months ending September 30, 2004 as compared to the same periods in the prior year 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 (refer to Regulatory Proceedings (Utilities), later). Also contributing to the increase during 2004 was the growth in residential, commercial, and industrial customers (3.0%, 2.6%, and 9.5% for the nine months ended September 30, 2004, respectively). Slightly offsetting these increases was cooler summer weather in 2004. Management expects the trend of higher 2004 retail revenues when compared to 2003 to continue for the remainder of 2004.

The decrease in Electric Operating Revenues-Other for the three and nine months ending September 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							Nine Months
	Ended September 30,							Ended September 30,
					Change from Prior							Change from Prior
	2004		2003		year %			2004		2003		year %
Gas Operating Revenues:
Residential	$	7,054	$	6,825		3.4	%	$	49,132	$	49,730		-1.2	%
Commercial		3,950		3,811		3.6	%		25,470		25,536		-0.3	%
Industrial		1,691		1,967		-14.0	%		7,959		9,999		-20.4	%

Retail revenue		12,695		12,603		0.7	%		82,561		85,265		-3.2	%
Wholesale revenue		3,048		682		346.9	%		13,049		27,275		-52.2	%
Miscellaneous		644		646		-0.3	%		2,132		1,881		13.3	%

Total Revenues	$	16,387	$	13,931		17.6	%	$	97,742	$	114,421		-14.6	%

Retail sales in thousands of decatherms		1,227		1,179		4.1	%		8,714		8,740		-0.3	%
Average retail revenues per decatherm	$	10.35	$	10.69		-3.2	%	$	9.47	$	9.76		-3.0	%

Retail gas revenues increased for the three months ending September 30, 2004 from the same periods in 2003 primarily due to an increase in customer usage resulting from colder temperatures in September 2004 and growth in residential and commercial customers of 4.3% and 2.6%, respectively. This increase was partially offset by a decrease in energy related rates that became effective November 1, 2003. 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).

Retail gas revenues decreased for the nine months ending September 30, 2004 from the same periods in 2003 primarily due to a decrease in energy related rates that became effective November 1, 2003, as discussed above. This decrease was partially offset by continued customer growth.

The decrease in industrial retail revenues for the three and nine months ended September 30, 2004, was attributable to a shift of industrial customers to SPPC’s gas transportation tariff and to the commercial gas tariff. Gas usage is manually reviewed once a year and accounts are migrated in October according to provisions included in the large commercial and industrial natural gas service tariffs.

Wholesale gas revenues increased significantly for the three months ending September 30, 2004 compared to the same period in 2003. This increase reflects sales of gas from Canada to California markets for resale which proved to be more favorable than during the same period in 2003. However, despite the increase in the third quarter of 2004, year-to-date revenues declined. Overall, US western region gas prices in 2004 have been higher than 2003 prices, contributing to a decrease in the year-to-date resale opportunities.

Purchased Power


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Purchased Power	$	92,481	$	125,337		-26.2	%	$	230,577	$	288,692		-20.1	%
Purchased Power in thousands of MWhs		1,622		2,017		-19.6	%		4,258		5,230		-18.6	%
Average cost per MWh of Purchased Power	$	57.02	$	62.14		-8.2	%	$	54.15	$	55.20		-1.9	%

Purchased power costs were lower for the three and nine months ended September 30, 2004, compared to the same periods in 2003 primarily due to lower volumes purchased. The decrease in volume was attributable to a decrease in wholesale electric sales as discussed in Electric Operating Revenues – Other and SPPC satisfying more of its load requirements through its own generation. See Fuel For Power Generation that follows.

Also contributing to lower purchased power costs, the average cost per MWh of purchased power decreased for the three and nine months ended September 2004 mainly due to a reduction in energy purchases associated with risk management activities.

Due to recent increases in the cost of natural gas, SPPC anticipates an increase in the average cost per MWh of purchase power during the fourth quarter of 2004.

Fuel For Power Generation


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Fuel for Power Generation	$	59,494	$	62,412		-4.7	%	$	166,715	$	143,144		16.5	%
Thousands of MWh generated		1,249		1,130		10.5	%		3,492		3,014		15.9	%
Average fuel cost per MWh of Generated Power	$	47.63	$	55.23		-13.8	%	$	47.74	$	47.49		0.5	%

Fuel for Power Generation costs decreased for the three months ended September 30, 2004, compared to the same period in 2003. The decrease resulted from lower coal prices that were partially offset by both an increase in natural gas prices and an increase in the volume of generation utilized to satisfy SPPC’s native load requirement. In contrast, Fuel for Power Generation costs increased for the nine months ended September 30, 2004, compared to the same period in 2003, primarily as a result of an increase in the volume of generation used to satisfy SPPC’s native load requirement. The average cost of fuel for power generation for the nine months ended September 30, 2004 was comparable to the same period in 2003.

SPPC expects that recent increases in natural gas prices will affect fuel for power generation costs adversely in the fourth quarter of 2004.

Gas Purchased for Resale


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2004		2003		Prior Year %			2004		2003		Prior Year %
Gas Purchased for Resale	$	11,322	$	7,133		58.7	%	$	73,721	$	77,332		-4.7	%
Gas Purchased for Resale (in thousands of decatherms)		2,025		1,525		32.8	%		11,234		14,100		-20.3	%
Average cost per decatherm	$	5.59	$	4.68		19.4	%	$	6.56	$	5.48		19.7	%

The cost of gas purchased for resale increased for the three months ended September 30, 2004, compared to the same period in 2003, primarily due to increases in natural gas prices and an increase in customer usage resulting from colder temperatures in September 2004 and continued customer growth.

The cost of gas purchased for resale decreased for the nine months ended September 30, 2004, compared to the same period in 2003, primarily due to a decrease in volume, which was primarily due to a decline in wholesale sales. The decrease in volume was partially offset by an increase in gas prices during the period.

SPPC expects the cost of gas purchased for resale to increase in the fourth quarter of 2004 due to an increase in natural gas prices and higher demand associated with winter months.

Deferred Energy Costs


	Three Months									Nine Months
	Ended September 30,									Ended September 30,
							Change from								Change from
	2004			2003			Prior Year %			2004		2003			Prior Year %
Deferred energy costs disallowed	$	—		$	—			N/A		$	—	$	45,000			-100.0	%
Deferred energy costs - electric - net		(3,269	)		(22,174	)		-85.3	%		1,436		(3,531	)		N/A
Deferred energy costs - gas - net		297			2,200			-86.5	%		266		14,023			-98.1	%

Total	$	(2,972	)	$	(19,974	)				$	1,702	$	55,492

Deferred energy costs disallowed for the nine months ended September 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.

Deferred energy costs - electric - net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through rates the difference is recognized as an increase in costs. Deferred energy costs – net also include the current amortization of fuel and purchased power costs previously deferred.

Deferred energy costs - electric - net increased for the three and nine months ended September 30, 2004, compared to the same periods in 2003, because actual fuel and purchased power costs exceeded amounts recovered through rates to a lesser extent during 2004 compared to the same period in 2003. The increase in deferred energy costs for both periods in 2004 was partially offset by a decrease in the amortization of prior deferred energy costs through current rates in 2004 compared to 2003.

Deferred energy costs - gas - net decreased for the three and nine months ended September 30, 2004, due to the lower amortization of prior deferred gas costs during 2004 compared to 2003 because of lower rates; and actual natural gas costs exceeding the recovery of those costs through current rates during 2004, but not during 2003.

Allowance For Funds Used During Construction (AFUDC)


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from					Change from
	2004		2003		Prior Year %			2004		2003 Prior Year %
Allowance for other funds used during construction	$	230	$	758		-69.7	%	$	1,513	$	1,961	-22.8	%
Allowance for borrowed funds used during construction	$	364	$	908		-59.9	%	$	2,498	$	2,219	12.6	%

	$	594	$	1,666		-64.3	%	$	4,011	$	4,180	-4.0	%

AFUDC was lower for the three month and nine month periods ended September 2004 compared to the same periods in 2003 due to a decrease in the Construction Work in Progress balance. The Falcon-Gonder transmission project was placed into service during the quarter ended June 2004, as a result, management believes AFUDC costs will be lower for the remainder of 2004.

Other (Income) and Expenses


	Three Months									Nine Months
	Ended September 30,									Ended September 30,
							Change from									Change from
	2004			2003			Prior Year %			2004			2003			Prior Year %
Other operating expense	$	29,899		$	26,684			12.0	%	$	93,601		$	87,522			6.9	%
Maintenance expense	$	5,212		$	4,769			9.3	%	$	15,570		$	16,409			-5.1	%
Depreciation and amortization	$	21,530		$	20,811			3.5	%	$	64,866		$	60,478			7.3	%
Income tax expense/(benefit)	$	9,424		$	(21	)		N/A		$	9,729		$	(16,229	)		N/A
Interest charges on long-term debt	$	17,307		$	19,174			-9.7	%	$	54,022		$	56,914			-5.1	%
Interest charges-other	$	928		$	15,675			-94.1	%	$	5,555		$	21,404			-74.0	%
Interest accrued on deferred energy	$	(1,635	)	$	(732	)		123.4	%	$	(3,972	)	$	(4,246	)		-6.5	%
Other income	$	(765	)	$	(1,450	)		-47.2	%	$	(2,521	)	$	(3,550	)		-29.0	%
Disallowed merger costs	$	—		$	—			N/A		$	1,929		$	—			N/A
Plant costs disallowed	$	—		$	—			N/A		$	47,092		$	—			N/A
Other expense	$	1,568		$	1,450			8.1	%	$	4,123		$	5,057			-18.5	%
Income taxes - - other income and expense	$	458		$	454			0.9	%	$	(14,900	)	$	1,233			N/A

Other operating expense increased for the three and nine months ended September 30, 2004 compared to the same periods in 2003, primarily due to amortization expense that is being recovered through rates for merger, goodwill and divestiture costs as well as costs incurred as a result of enhanced collection efforts on overdue customer accounts.

Maintenance costs for the three month period ended September 30, 2004 increased compared to the prior year and decreased during the nine month period ended September 30, 2004, due to several items, none of which were individually significant.

Depreciation and amortization expense increased for the three month and nine month periods ended September 30, 2004 compared to the same periods in 2003 as a result of an increase in plant-in-service and an increase in depreciation rates approved by the California Public Utilities Commission 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 2004.

SPPC recognized income tax expense for the three and nine months ended September 30, 2004, compared to income tax benefits recognized for 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 decrease in fuel expenses, resulting in less of a benefit recognized, as well as the recognition in the second quarter of 2003 of tax benefits resulting from the partial resolution of an Internal Revenue Service audit.

SPPC’s interest charges on long-term debt decreased slightly during the three and nine months ended September 30, 2004 compared to the same periods in 2003 as a result of lower long-term debt balances as a result of the redemption in December 2003 of $18 million of debt, the reduction in interest rate during 2004 associated with the replacement of its 10.5% $100 million 3 year Notes with 6.25% $100 million Series H Notes and a reduction in interest rate in April, 2004, of SPPC’s $80M Washoe Water bonds from 7.5% to 5.0%.

Interest charges-other for the three and nine months ended September 30, 2004, were significantly lower than the comparable periods in 2003 due to the recording in September 2003 of approximately $12 million interest expense related to the Enron terminated contract liability. Additionally, SPPC recognized lower interest charges related to the accounts receivable facility during the three and nine months ended September 30, 2004, when compared to the same periods in 2003.

Interest accrued on deferred energy costs increased during the three months ended September 30, 2004, compared to the same period during 2003 as a result of higher deferred fuel and purchased power balances in 2004 and a rate increase granted by the PUCN in June 2004. Conversely, interest accrued on deferred energy costs were lower during the nine months ended September 30, 2004, compared to the same periods 2003, due to lower deferred fuel and purchased power balances, partially caused by action of the PUCN in ordering the write-off of some of the balances in June 2003. (Refer to Regulatory Proceedings (Utilities) for discussion of deferred energy issues).

SPPC’s Other income decreased during the three and nine months ended September 30, 2004 from the comparable periods in 2003 due to lower interest income and the gain recognized in 2003 from the sale of non-utility property.

Disallowed merger costs expense for the nine months ended September 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 by the PUCN to disallow recovery of a portion of the costs associated with the Piñon Pine power plant project. See Note 4 of the Condensed Notes to Consolidated Financial Statements, Regulatory Proceedings for details.

SPPC’s Other expense decreased for the three months ended September 30, 2004, compared to the same period in 2003 due to costs associated with SPPC’s Supplementary Executive Retirement Plan which were disallowed by the PUCN in 2004, increases in and charges related to advertising activities, partially offset by decreased costs associated with SPPC’s assistance programs. For the nine months ended September 30, 2004, Other expense decreased from the same period in 2003 following primarily, decreased charges for assistance programs, lobbying and advertising activities.

Income taxes – other income and expense for the three month period ending September 30, 2004, was comparable to the same period in the prior year. Income taxes – other income and expense changed from income tax expense recognized for the nine months ended September 30, 2003, to income tax benefit recognized during the same period in 2004. The 2004 tax benefit was recognized primarily as a result of an impairment charge associated with the Piñon Pine generating facility during the second quarter of 2004. See Note 4 of 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 nine months ended September 30, 2004 increased when compared to the same period in 2003 as a result of an increase in cash from operating activities and a decrease in cash flows used in investing activities, offset by a decrease in cash from financing activities. The increase in cash flows from operating activities resulted primarily from rate increases implemented in June 2004, which resulted in higher margins, offset by the cash payment of $11 million to the Enron escrow account. Cash flows for investing activities decreased primarily due to the completion of major construction activities associated with the Falcon to Gonder project. Cash flows from financing activities decreased due to the repayment of $25 million in short-term borrowing in March 2004.

LIQUIDITY AND CAPITAL RESOURCES

SPPC had cash and cash equivalents of approximately $35 million at September 30, 2004.

SPPC anticipates capital requirements for construction costs during 2004 will be approximately $112 million, of which $66 million has been spent through September 30, 2004. SPPC anticipates capital requirements for construction during 2005 will be approximately $170 million. SPPC expects to finance these costs with internally generated funds, including the recovery of deferred energy. Through October 31, 2004, SPPC has issued and/or refinanced maturing debt and its revolving credit facility to support its operations, including purchasing power and supporting construction costs.

Mortgage Indentures

SPPC’s First Mortgage Indenture creates a first priority lien on substantially all of SPPC’s properties in Nevada and California. As of September 30, 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 September 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 October 31, 2004, SPPC had the capacity to issue approximately $322 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

On October 22, 2004, SPPC terminated its $50 million long-term revolving credit facility, which had been established on May 4, 2004, and replaced it with a three year revolving credit facility of $75 million. In this new credit facility, $25 million of the $75 million is short-term (364 day) until such time as the utility receives long-term debt authority from the PUCN for the additional $25 million. SPPC has not yet determined whether it will seek such long-term authority.

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.


	General and Refunding Mortgage Notes, Series H

On April 16, 2004, SPPC issued and sold $100 million of its 6¼% 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, as with the Series E Bond, 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.


	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

The Credit Agreement provides for certain events of default including any of the following events: SPPC fails to make payments of principal or interest under the Credit Agreement, SPPC fails to comply with certain agreements included in the Credit Agreement, SPPC files for bankruptcy, or a change of control occurs. The Credit Agreement also provides for an event of default if a judgment of $15 million or more is entered against SPPC and such judgment is not vacated, discharged, stayed or bonded pending appeal within 60 days. Since, the Credit Agreement also prohibits the creation or existence of any liens on SPPC’s properties except for liens specifically permitted under the Credit Agreement, if a judgment lien is filed against SPPC, the filing of the lien will trigger an event of default under the Credit Agreement. The Credit Agreement also provides for an event of default if SPPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million.

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 September 30, 2004, provides for an event of default if a matured event of default under SPPC’s First Mortgage Indenture occurs;

•		The terms of SPPC’s Series H Notes and Series E 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 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 and the Series E Bond to require SPPC to redeem their series of Notes or Bonds, 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; and

•		SPPC’s $75 million Credit Agreement provides for an event of default if SPPC defaults in the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, relating to debt in excess of $15 million. Upon an event of default, the Administrative Agent under the SPPC Credit Agreement may, upon request of more than 50% of the lenders under the Credit Agreement, declare all amounts due under the Credit Agreement immediately due and payable. Since SPPC’s obligations under the Credit Agreement are secured by its General and Refunding Mortgage Bond, if SPPC fails to repay all amounts due upon an acceleration of the Credit Agreement within three business days, such failure will be deemed a default in the payment of principal and will trigger an event of default under SPPC’s General and Refunding Mortgage Indenture that would be applicable to all securities issued under SPPC’s General and Refunding Mortgage Indenture.

Judgment Related Defaults

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.

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:

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, the Series E Bond and the SPPC Revolving 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, 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 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.

Financial Covenants

SPPC’s $75 million Revolving Credit Agreement dated October 22, 2004, contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.

Due to a negative pledge obligation in SPPC’s $92 million General and Refunding Mortgage Bond, Series E, SPPC expects to amend its Series E Bond to include these two financial maintenance covenants. SPPC’s Series E Bond, which is currently held by an escrow agent, was issued to secure the Enron Judgment. (See Note 9 – “Commitments and Contingencies” for a discussion of the Enron Judgment) Although the Judgment was vacated in a decision handed down on October 10, 2004 by the U.S. District Court for the Southern District of New York, the Series E Bond will continue to remain in escrow through the pendancy of all remands and appeals pursuant to a stipulation and agreement previously entered into among NPC, SPPC and Enron.

Contractual Obligations

During the nine months ended September 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 other than the April 2004 issuance of SPPC’s $100 million 6.25% General and Refunding Mortgage Notes, Series H, due April 15, 2012, which were issued to pay off SPPC’s $100 million Term Loan Facility, and the May 2004 establishment of a $50 million Revolving Credit Facility, which was terminated on October 22, 2004. On October 22, 2004, SPPC established a $75 million Revolving Credit Facility for general corporate purposes, which replaced SPPC’s previously established $50 million Revolving Credit Facility.

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

NPC filed its biennial General Rate Case on October 1, 2003, as required by law. NPC requested a $142 million increase in the annual revenue requirement for general rates.

•		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 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 June 7, 2004 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

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. On October 16, 2004, NPC filed a petition requesting that delayed implementation and ordered or anticipated changes be made at the same time on April 1, 2005 in order to stabilize rates and reduce the number of rate changes.

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 6½% General and Refunding Mortgage Notes, Series I, due 2012 and for its $100 million revolving credit facility that was established on May 4, 2004.


	NPC Application for $500 Million Long-Term Debt Authority

See Chuck Lenzie Generating Station Financing Plan under NPC’s Liquidity and Capital Resources Section and Nevada Power Company Second Amendment to its 2003 Resource Plan, later in this 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 requested PUCN authorization to acquire a partially completed power plant, the “Chuck Lenzie Generating Station”, from Duke Energy for $182 million. This amendment requested approval to substitute the 1200 MW Chuck Lenzie Generating Station, which is expected to become operational in early 2006, for the previously approved Harry Allen 520 MW combined cycle generator, which is to come on line in 2007.

The transaction with Duke Energy closed on October 13, 2004. A future general rate case will be required before NPC can include the costs for this facility in customers’ rates.

Nevada Power Company Third Amendment to its 2003 Resource Plan

NPC filed a third amendment to its 2003 Resource Plan to comply with previous PUCN orders requiring NPC to explore alternatives or reaffirmation of the Harry Allen to Mead 500kV transmission line. This Amendment requests the PUCN reaffirm the need for the Harry Allen to Mead line as well as other modifications to its transmission plan. A PUCN hearing is scheduled for November 22, 2004.

Nevada Power Company Fourth Amendment to its 2003 Resource Plan

On November 2, 2004, NPC filed a fourth amendment to its 2003 Resource plan in compliance with previous PUCN orders calling for an annual update of the DSM programs, the addition of a Residential High Efficiency Air Conditioner program, and the addition of a Solar Photovoltaic program associated with NPC facilities. NPC requested approval of other adjustments to its DSM programs as well.

Nevada Power Company Fifth Amendment to its 2003 Resource Plan

Also in November 2004, NPC expects to file a fifth amendment to its 2003 Resource Plan requesting approval of two new renewable energy credit contracts and revision to four previously approved renewable energy contracts.

Sierra Pacific Power Company 2003 General Rate Case

•		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.

SPPC filed its opening brief in early October. Answering and Reply briefs are scheduled for November and December and the hearings are expected to occur in the first quarter of 2005. SPPC does not know the timing of a decision from this court.

Sierra Pacific Power Company 2004 Deferred Energy Case

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 SPPC. 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 Annual Purchased Gas Cost Adjustment

The parties agreed to a stipulation, which recommended the PUCN approve the requested rates and the PUCN issued an order approving the rate increase on October 27, 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 6¼% 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 Statements, Long-Term Debt) and for its $50 million revolving credit facility, which was terminated and replaced with a $75 million Revolving Credit Facility, $50 million of which is long-term under this authority.

Sierra Pacific Power Company 2004 Resource Plan

Additionally SPPC is seeking PUCN approval on the following items:

•		Designation of the combined cycle plant as a “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.

Intervener’s filed testimony on September 24, 2004. The following summarizes their positions on significant issues:

•

Critical facility designation and associated enhanced ROE for investment in 500 MW combined cycle plant

The Staff recommended that the PUCN authorize SPPC to go forward with permitting and development activities associated with the construction of the Tracy 500 MW combined cycle project, but require SPPC to file a resource plan amendment on or before August 1, 2005, to reaffirm the need for the 500 MW capacity addition and to clarify the cost, timing and configuration of the project to be constructed. The Staff also requested that the PUCN withhold any finding of whether the facility should be classified as a “critical facility” until the amended filing is made. The BCP argued that the facility should not be classified as a “critical facility” or in the event that it is classified as a “critical facility,” to reduce the requested incentive package.

•

Energy Supply Plan

The Staff testimony supports SPPC’s energy supply plan with the caveat that SPPC should be held accountable for its “response to future changes in the operational conditions and assumptions underlying” SPPC’s recommendations. The BCP takes issue with SPPC’s energy supply plan and recommends the PUCN order SPPC, the Staff and other parties to identify and evaluate other procurement approaches.

SPPC and parties reached agreement on the issues and presented their stipulation to the PUCN on October 12, 2004. The stipulation calls for budget adjustments in the Demand Side Management programs and continued discussions to develop a new cost/benefit test for such programs. The stipulation authorizes SPPC to proceed with permitting activities for a 500 MW combined cycle power plant as requested and requires SPPC to file a Resource Plan Amendment to reaffirm the need for the 500 MW capacity addition before August 1, 2005. SPPC’s request for a “critical facility” designation and the associated enhanced ROE was deferred for consideration during the amendment proceedings. All other supply side proposals were approved as filed. A Commission order is expected to be rendered on or before November 13, 2004.

Other Nevada 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. Following the PUCN approval, Barrick provided official notice of departure to SPPC on October 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 deferred regulatory account. Beginning upon Barrick’s departure and continuing until rates are set through SPPC’s next subsequent general rate proceeding, SPPC will record $650,000 monthly to the regulatory account 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 account. The net balance of the deferred regulatory account 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 SPPC’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.

Newmont mining company filed a Notice of Intent on July 16, 2004 to depart SPPC’s system in mid 2008. To date no application has been made.


	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.

In October 2004, NPC contracted with two renewable energy producers to purchase Renewable Energy Credits from existing and to be constructed solar generating facilities. The contracts are expected to improve NPC’s ability to meet its solar energy sources requirement beginning in 2005.


	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. The PUCN agreed to amend its regulations to establish the TRED program at its September 29, 2004 agenda meeting.

It is anticipated that the TRED program will assist developers of new renewable energy projects in successfully financing their projects, thereby resulting in a higher rate of completion for new renewable energy projects with PUCN-approved contracts, thereby allowing the utilities to more quickly satisfy their renewable energy portfolio requirements.

Specifically the TRED program will establish a TRED charge to separately collect revenues from customers necessary to pay renewable energy suppliers under PUCN-approved contract. TRED program revenues will be forwarded into a special purpose trust that will in turn remit payment to approved renewable energy projects that deliver renewable energy to the purchasing utility under PUCN-approved contracts.

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. Pre-hearing conferences were held on July 14 and August 4, 2004. On August 16, 2004, the CPUC Office of Ratepayer Advocates issued a report recommending the CPUC accept SPPC’s ECAC proposal with a minor change to the rate design calculations. SPPC accepts the change and resulting decrease to the request of $.013 million. On October 4, 2004, the CPUC issued a draft order recommending approval of SPPC’s adjusted ECAC proposal. No hearings are necessary and a decision followed by rate implementation is expected to occur in the fourth quarter of 2004.

FERC Matters


	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 July 8, 2004, FERC approved a settlement issued on June 14, 2004. The Utilities have issued refunds for amounts collected in excess of settlement rates and filed a report of such refunds at the FERC as instructed in the July 8 order.

On October 1, 2004, the Utilities filed with the FERC revised rates for transmission service offered by SPPC under Docket No. ER05-14. The purpose of the filing was to update rates to reflect recent transmission additions and to improve rate design. A procedural schedule should be issued by December 1, 2004.


	Open Access Transmission Tariff Audit

On August 30, 2004, the FERC announced that it was commencing an audit to determine whether and how SPPC and NPC and their affiliates are complying with the Open Access Transmission Tariff, Market-Based Rate Tariff, and Codes of Conduct. The audit is being conducted by the FERC’s Division of Operational Audits of the Office of Market Oversight and Investigations. The auditors have conducted on-site visits at both utilities and have issued requests for data. Follow-up on-site visits are scheduled for later this year.


	California Refunds

NPC and SPPC are participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001. The California parties have contested the FERC’s decision to limit the timeframe for the recalculations and a recent Ninth Circuit court decision remanded a related issue to the FERC, therefore NPC and SPPC are not able to determine the eventual magnitude of refunds that may result from this FERC process. The California Independent System Operator and the bankrupt California Power Exchange currently owe the utilities approximately $22 million for power delivered during the west coast energy crisis and the utilities booked a reserve against those receivables in 2001. Current estimates of refunds that may result from the recalculated prices for the October 2, 2000 to June 20, 2001 timeframe do not exceed the $22 million owed to the Utilities.

RECENT PRONOUNCEMENTS

FIN 46 (R)

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 (QFs), jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven 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) due 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 September 30, 2004.

FSP FAS 106-2

The Financial Accounting Standards Board (FASB) issued a Staff Position (FSP) to modify Statement of Financial Accounting Standards 106 (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 (the “Act”), signed into law on December 8, 2003. This FSP 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 has tentatively concluded that its prescription drug plan would qualify for the federal subsidy under this Act.

Final guidelines were issued by the Department of Health and Human Services on July 26, 2004, and SPR completed its evaluation of the impact of this Act on its postretirement benefit expense. SPR elected to adopt FSP FAS 106-2 prospectively, valuing the annual benefit of the subsidy as of April 1, 2004, and recognizing one half of this amount in the third and fourth quarters. (The April 1 valuation was required for companies using an annual measurement date of September 30 for pension plans, and electing to adopt FSP FAS 106-2 prospectively.) The valuation resulted in an annual reduction to other postretirement benefit costs of $0.8 million. Accordingly, SPR will recognize $0.2 million in each, the third and fourth quarters of 2004. Also refer to Note 13 of the Condensed Notes to Consolidated Financial Statements, Pension and Other Postretirement Benefits.

FSP FAS 129-1

EITF 03-6

The Emerging Issues Task Force (EITF) of the FASB nullified the guidelines given in EITF Topic D-95 with regards to the effect of participating convertible securities on the computation of basic earnings per share by issuing EITF 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128. Under Topic D-95 (See Note 10 of the Condensed Notes to Consolidated Financial Statements, Earnings Per Share), companies were required to use either the “two-class” or the “if-converted” method to account for potential dilution due to participating convertible securities that could be converted into common stock, if the effect was dilutive. This was to be used in the calculation of basic and diluted earnings per share.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 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. The book value and fair value of SPR, NPC and SPPC debt as of September 30, 2004 was (dollars in thousands):

Expected Maturity Date


	2004			2005			2006			2007			2008			Thereafter⁽²⁾			Total			Fair Value
Long-term Debt
SPR
Fixed Rate	$	11,550	⁽¹⁾	$	—		$	—		$	240,218		$	—		$	635,000		$	886,768		$	1,220,385
Average Interest Rate		8.00	%		0.00	%		0.00	%		7.93	%		0.00	%		7.98	%		7.96	%
NPC
Fixed Rate	$	4		$	15		$	15		$	17		$	13		$	1,863,548		$	1,863,612		$	1,990,670
Average Interest Rate		8.17	%		8.17	%		8.17	%		8.17	%		8.17	%		8.00	%		8.10	%
Variable Rate																$	115,000		$	115,000		$	115,000
Average Interest Rate																	1.74	%		1.74	%
SPPC
Fixed Rate	$	522		$	2,400		$	52,400		$	2,400		$	322,400		$	617,850		$	997,972		$	1,037,796
Average Interest Rate		6.10	%		6.10	%		6.72	%		6.10	%		7.99	%		6.52	%		7.90	%

Total Debt	$	12,076		$	2,415		$	52,415		$	242,635		$	322,413		$	3,231,398		$	3,863,352		$	4,363,851

(1)

SPR includes the debt of Sierra Pacific Communications of $11.6 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 $239.9 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 $30 million as of September 30, 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 September 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 third quarter of 2004 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.


	(c) Sarbanes-Oxley Section 404 compliance.

Section 404 of the Sarbanes-Oxley Act of 2002 (the “Act”) will require the Company to include an internal control report from management in its Annual Report on Form 10-K for the year ended December 31, 2004 and in subsequent Annual Reports thereafter. The internal control report must include the following: (1) a statement of management’s responsibility for establishing and maintaining adequate internal control over financial reporting, (2) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of the Company’s internal control over financial reporting, (3) management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, including a statement as to whether or not internal control over financial reporting is effective, and (4) a statement that the Company’s independent auditors have issued an attestation report on management’s assessment of internal control over financial reporting.

Management acknowledges its responsibility for establishing and maintaining internal controls over financial reporting and seeks to continually improve those controls. In addition, in order to achieve compliance with Section 404 of the Act within the required timeframe, the Company has been conducting a process to document and evaluate its internal controls over financial reporting since early 2004. In this regard, the Company has dedicated internal resources, engaged outside consultants and adopted a detailed work plan to: (i) assess and document the adequacy of internal control over financial reporting; (ii) take steps to improve control processes where required; (iii) validate through testing that controls are functioning as documented; and (iv) implement a continuous reporting and improvement process for internal control over financial reporting. The Company believes its process for documenting, evaluating and monitoring its internal control over financial reporting is consistent with the objectives of Section 404 of the Act.

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

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.

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.

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

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

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

The District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The District Court rejected Enron’s cross-appeal seeking a 12% per year post-judgment interest rate instead of the 1.21% interest rate ordered by the Bankruptcy Court. The Utilities do not know whether Enron will appeal this portion of the District Court’s decision or the timing of any such appeal. The District Court decision also provides that Enron may, if proper, renew its motion to enjoin the proceedings currently before the FERC addressing Enron’s termination of its power supply contracts with NPC and SPPC. The Utilities continue to assess the impact of the District Court’s decision. Although the Judgment has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron, discussed above, will remain in place through the pendency of all remands and appeals of the Judgment.

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 below. 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. On October 27, 2004, Enron filed a motion in the Bankruptcy court to enjoin the Utilities from participating in the FERC 206 proceeding. The Utilities plan to oppose the motion and a hearing is scheduled for late November 2004.


	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. Oral argument is scheduled for December 8, 2003. 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. Hearings were scheduled to begin on October 25, 2004 and an initial decision was expected from the FERC by December 31, 2004. However, on October 12, 2004, after learning on the same day that Enron had not produced and would not be able to produce by the scheduled October 25th hearing date approximately 900,000 documents and approximately 84,000 emails that are potentially responsive to the Utilities’ document requests, the Utilities filed an emergency motion to delay the hearings to ensure that hearings will be based on a full record after adequate time for discovery. All parties in the dispute supported the delay. As a result, on October 13, 2004, the Chief Administrative Law Judge at the FERC suspended the prior deadline for an initial decision in the matter from December 31, 2004 to February 14, 2005. The hearings have been rescheduled for the week of December 13, 2004. The Utilities are unable to predict the outcome of this FERC proceeding or whether FERC’s decision will affect the Bankruptcy Court’s reconsideration of this matter and any subsequent appeals of the Judgment or related matters and cases.

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 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 in May 2005. 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. At this time we are unable to state the likelihood of a potential favorable outcome of the appeal.


	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 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 the 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 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 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). On August 11, 2004, NPC filed a motion to continue the stay, and on October 4, 2004, the Court granted the stay for another 90 days. At this time, NPC is unable to predict the outcome or timing of the District Court complaint.


	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.

Nevada Power Company 2001 Deferred Energy Case

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

On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. NPC and the BCP both sought individual review of the Commission Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal to the Nevada Supreme Court. Supreme Court rules mandate settlement talks before a matter is set for briefing and argument. The Settlement Judge has yet to recommend closure of the settlement process given current caseloads at the Supreme Court. Briefing, oral argument and a decision are not expected to occur until 2005. NPC is not able to predict the outcome of the process or of the Supreme Court’s deliberation on the matter. Additionally, NPC filed a petition for judicial review with the Nevada Supreme Court to remand this matter back to the PUCN to consider evidence uncovered after the PUCN’s final decision. On November 2, 2004, the Nevada Supreme Court issued an order denying the motion for remand.

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	Environmental Matters

In August 2004, NDEP conducted a Facility Air Quality Operating Permit (“Title V”) inspection at the Reid Gardner Station. Monitoring, recordkeeping and other reporting items including data quality assurance, CEMS maintenance procedures, and recorded oil/coal data pertaining to the sources identified in the Title V permit were requested. NPC has provided information in connection with this request and subsequent requests. In September and October 2004, NPC met with the NDEP to review the outcome of their inspection. NDEP informed NPC that it may not be in compliance with certain aspects of its Title V permit and is likely to issue a Notice of Alleged Violation (NOAV), unless, NPC provides additional documentation which supports its compliance with Title V permit regulations. NPC is continuing to provide information to NDEP as requested. Because NPC has not received a NOAV, management cannot reasonably estimate any potential monetary penalties at this time.

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). SPPC filed its opening brief in early October. Answering and Reply briefs are scheduled for November and December and the hearings are expected to occur in the first quarter of 2005. SPPC does not know the timing of a decision from this court.

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 the hearing, originally scheduled for September 23, 2004, has been rescheduled for November 29, 2004.

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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

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 quarters ended March 31, 2004 and June 30, 2004. No other material developments have occurred with respect to the litigation described in the 10-K and the 10-Qs.

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

None

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS

Exhibits filed with this Form 10-Q:

Nevada Power Company


Exhibit 10.1		Moapa Energy Facility Purchase Agreement

Exhibit 10.2		Moapa Energy Facility Amendment to Purchase Agreement

Exhibit 10.3		Engineering, Procurement and Construction Agreement between Nevada Power Company and Fluor Enterprises, Inc.

Exhibit 10.4		Exhibit A to Engineering, Procurement and Construction Agreement between Nevada Power Company and Fluor Enterprises, Inc.

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Exhibit 10.5		Amended and Restated Credit Agreement dated October 22, 2004 among Nevada Power Company, the banks named therein and the other lenders from time to time party thereto and Union Bank of California, N.A., as administrative agent.

Sierra Pacific Power Company

Exhibit 10.6		Credit Agreement dated October 22, 2004 among Sierra Pacific Power Company, the banks named therein and the other lenders from time to time party thereto and Union Bank of California, N.A., as 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.

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SIGNATURE

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


		Sierra Pacific Resources
		(Registrant)

Date: November 9, 2004		/s/ Michael W. Yackira

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

Date: November 9, 2004	By:	/s/ John E. Brown

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

		Nevada Power Company
		(Registrant)

Date: November 9, 2004	By:	/s/ Michael W. Yackira

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

Date: November 9, 2004	By:	/s/ John E. Brown

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

		Sierra Pacific Power Company
		(Registrant)

Date: November 9, 2004	By:	/s/ Michael W. Yackira

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

Date: November 9, 2004	By:	/s/ John E. Brown

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

104

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

Nv Energy (NVE) Inactive 10-Q2004 Q3 Quarterly report

Content analysis