Sierra Pacific Power 10Q 2005 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2005


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


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

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

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

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

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether any registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Sierra Pacific Resources; Yesþ Noo; Nevada Power Company Yeso Noþ; Sierra Pacific Power Company; Yeso Noþ

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


Class		Outstanding at May 3, 2004
Common Stock, $1.00 par value of Sierra Pacific Resources		117,569,828 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 MARCH 31, 2005

CONTENTS

PART I — FINANCIAL INFORMATION


ITEM 1. Financial Statements

Sierra Pacific Resources -
Consolidated Balance Sheets – March 31, 2005 and December 31,2004			3

Consolidated Statements of Operations – Three Months Ended March 31,2005 and 2004			5

Consolidated Statements of Cash Flows – Three Months Ended March 31,2005 and 2004			6

Nevada Power Company -
Consolidated Balance Sheets – March 31, 2005 and December 31,2004			7

Consolidated Statements of Operations – Three Months Ended March 31,2005 and 2004			8

Consolidated Statements of Cash Flows – Three Months Ended March 31,2005 and 2004			9

Sierra Pacific Power Company -
Consolidated Balance Sheets – March 31, 2005 and December 31, 2004			10

Consolidated Statements of Operations – Three Months Ended March 31, 2005 and 2004			11

Consolidated Statements of Cash Flows – Three Months Ended March 31, 2005 and 2004			12

Condensed Notes to Consolidated Financial Statements			13

ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Sierra Pacific Resources			32
Nevada Power Company			35
Sierra Pacific Power Company			40

ITEM 3.Quantitative and Qualitative Disclosures about Market Risk			48

ITEM 4.Controls and Procedures			49

PART II — OTHER INFORMATION
ITEM 1.Legal Proceedings			49

ITEM 4.Submission of Matters to a Vote of Security Holders			55

ITEM 5.Other Information			55

ITEM 6.Exhibits			55

Signature Page and Certifications			56
EX-10.1 Collective Bargaining Agreement dated as of February 1, 2005
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)


	March 31,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,664,413	$	6,604,449
Less accumulated provision for depreciation		2,123,904		2,083,434

		4,540,509		4,521,015
Construction work-in-progress		502,417		405,911

		5,042,926		4,926,926

Investments and other property, net		62,739		64,596


Current Assets:
Cash and cash equivalents		282,739		266,328
Restricted cash and investments (Note 1)		75,667		88,452
Accounts receivable less allowance for uncollectible accounts:
2005-$36,689; 2004-$36,197		292,319		320,676
Deferred energy costs — electric (Note 1)		128,288		148,008
Deferred energy costs — gas (Note 1)		4,346		3,106
Materials, supplies and fuel, at average cost		77,245		76,193
Risk management assets (Note 5)		60,947		14,585
Deposits and prepayments for energy		36,582		54,767
Other		32,915		37,494

		991,048		1,009,609


Deferred Charges and Other Assets:
Goodwill (Note 8)		22,877		22,877
Deferred energy costs — electric (Note 1)		506,656		526,159
Deferred energy costs — gas (Note 1)		1,699		2,491
Regulatory tax asset		280,032		279,766
Other regulatory assets		480,909		487,762
Risk management regulatory assets — net (Note 5)		—		6,673
Unamortized debt issuance expense		65,187		67,204
Other		119,693		114,297

		1,477,053		1,507,229

Assets of Discontinued Operations		20,115		20,107

TOTAL ASSETS	$	7,593,881	$	7,528,467

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

(Continued)

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,		December 31,
	2005		2004
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	1,488,158	$	1,498,616
Preferred stock		50,000		50,000
Long-term debt		4,060,012		4,081,281

		5,598,170		5,629,897

Current Liabilities:
Current maturities of long-term debt		28,593		8,491
Accounts payable		196,160		179,559
Accrued interest		88,227		69,246
Dividends declared		1,044		1,046
Accrued salaries and benefits		23,825		28,547
Deferred income taxes		34,081		54,501
Risk management liabilities (Note 5)		2,085		9,902
Accrued taxes		4,919		5,470
Contract termination liabilities (Note 6)		304,334		303,460
Other current liabilities		40,643		38,702

		723,911		698,924

Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes		532,191		512,760
Deferred investment tax credit		41,249		42,064
Regulatory tax liability		39,762		40,575
Customer advances for construction		148,060		142,703
Accrued retirement benefits		78,970		67,907
Risk management regulatory liability — net (Note 5)		35,128		—
Contract termination liabilities (Note 6)		36,984		36,753
Regulatory liabilities		262,314		257,495
Other		86,942		89,189

		1,261,600		1,189,446

Liabilities of Discontinued Operations		10,200		10,200

TOTAL CAPITALIZATION AND LIABILITIES	$	7,593,881	$	7,528,467

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

(Concluded)

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)


	Three Months Ended
	March 31,
	2005			2004
OPERATING REVENUES:				As Revised (Note 1)
Electric	$	581,144		$	528,374
Gas		67,538			59,476
Other		292			267

		648,974			588,117

OPERATING EXPENSES:
Operation:
Purchased power		220,152			193,491
Fuel for power generation		110,002			103,157
Gas purchased for resale		53,480			47,917
Deferred energy costs disallowed		—			1,586
Deferral of energy costs — electric — net		40,116			47,889
Deferral of energy costs — gas — net		(328	)		(1,407	)
Impairment of goodwill		—			11,695
Other		87,590			73,089
Maintenance		22,946			24,888
Depreciation and amortization		52,789			49,937
Taxes:
Income tax benefit		(7,830	)		(22,062	)
Other than income		11,109			11,851

		590,026			542,031

OPERATING INCOME		58,948			46,086

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,809			1,373
Interest accrued on deferred energy		6,108			6,549
Disallowed merger costs		—			(5,890	)
Other income		10,139			8,639
Other expense		(4,266	)		(3,125	)
Income taxes		(3,264	)		(1,558	)

		12,526			5,988

Total Income Before Interest Charges		71,474			52,074

INTEREST CHARGES:
Long-term debt		78,427			75,460
Other		6,166			21,587
Allowance for borrowed funds used during construction		(4,603	)		(2,173	)

		79,990			94,874


LOSS FROM CONTINUING OPERATIONS		(8,516	)		(42,800	)

DISCONTINUED OPERATIONS:

Income (Loss) from discontinued operations (net of income taxes (benefits) of $3 and $(353) respectively)		5			(675	)


NET LOSS		(8,511	)		(43,475	)
Preferred stock dividend requirements of subsidiary		975			975

DEFICIT APPLICABLE TO COMMON STOCK	$	(9,486	)	$	(44,450	)


Amount per share basic and diluted — (Note 7)
Loss from continuing operations	$	(0.07	)	$	(0.37	)
Deficit applicable to common stock	$	(0.08	)	$	(0.38	)

Weighted Average Shares of Common Stock Outstanding — basic and diluted		117,549,912			117,239,947

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)


	For the three months ended
	March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:				As Revised (Note 1)
Net Loss	$	(8,511	)	$	(43,475	)
Non-cash items included in net loss:
Depreciation and amortization		52,789			49,941
Deferred taxes and deferred investment tax credit		(4,442	)		(20,991	)
AFUDC and capitalized interest		(8,412	)		(3,546	)
Amortization of deferred energy costs — electric		54,647			56,743
Amortization of deferred energy costs — gas		(466	)		2,015
Deferred energy costs disallowed		—			1,586
Goodwill impairment		—			11,695
Other non-cash		511			(37,997	)
Changes in certain assets and liabilities:
Accounts receivable		28,357			28,787
Deferral of energy costs — electric		(15,423	)		(15,338	)
Deferral of energy costs — gas		18			(3,487	)
Materials, supplies and fuel		(1,052	)		4,893
Other current assets		22,764			(1,536	)
Accounts payable		16,601			(5,559	)
Escrow payment for terminating suppliers		—			(35,161	)
Other current liabilities		17,214			21,675
Change in net assets of discontinued operations		(8	)		70
Other assets		(39,527	)		14,468
Other liabilities		32,792			1,486

Net Cash from Operating Activities		147,852			26,269


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(165,101	)		(70,656	)
AFUDC and other charges to utility plant		8,412			3,546
Customer advances for construction		5,357			4,903
Contributions in aid of construction		4,032			6,769

Net cash used for utility plant		(147,300	)		(55,438	)
Investments in subsidiaries and other property — net		4,043			1,692

Net Cash used by Investing Activities		(143,257	)		(53,746	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings		—			(25,000	)
Change in restricted cash and investments		12,786			(129,863	)
Proceeds from issuance of long-term debt		—			335,000
Retirement of long-term debt		(1,167	)		(174,863	)
Sale of common stock, net of issuance cost		1,174			81
Dividends paid		(977	)		(968	)

Net Cash from Financing Activities		11,816			4,387


Net Increase (Decrease) in Cash and Cash Equivalents		16,411			(23,090	)
Beginning Balance in Cash and Cash Equivalents		266,328			181,757

Ending Balance in Cash and Cash Equivalents	$	282,739		$	158,667

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	64,509		$	70,044

Noncash Activities:
Transfer of Regulatory Asset	$	—		$	197,998

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	4,056,242	$	4,015,125
Less accumulated provision for depreciation		1,133,579		1,112,335

		2,922,663		2,902,790
Construction work-in-progress		449,693		355,431

		3,372,356		3,258,221


Investments and other property, net		28,954		30,809


Current Assets:
Cash and cash equivalents		187,716		243,323
Restricted cash (Note 1)		50,311		50,311
Accounts receivable less allowance for uncollectible accounts:
2005-$30,984; 2004-$30,900		164,201		178,077
Deferred energy costs — electric (Note 1)		101,020		126,074
Materials, supplies and fuel, at average cost		41,953		44,858
Risk management assets (Note 5)		26,996		5,092
Deposits and prepayments for energy		15,849		23,091
Other		23,302		23,721

		611,348		694,547

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		363,782		375,120
Regulatory tax asset		168,390		167,221
Other regulatory assets		273,670		277,450
Risk management regulatory assets — net (Note 5)		—		3,555
Unamortized debt issuance expense		42,591		43,802
Other		30,871		32,815

		879,304		899,963

TOTAL ASSETS	$	4,891,962	$	4,883,540


CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,407,563	$	1,436,788
Long-term debt		2,272,669		2,275,690

		3,680,232		3,712,478

Current Liabilities:
Current maturities of long-term debt		6,195		6,091
Accounts payable		132,406		114,242
Accounts payable, affiliated companies		1,303		3,920
Accrued interest		57,051		40,677
Dividends declared		399		399
Accrued salaries and benefits		10,468		12,780
Deferred income taxes		23,083		36,981
Risk management liabilities (Note 5)		549		3,555
Accrued taxes		3,194		2,441
Contract termination liabilities (Note 6)		212,231		211,620
Other current liabilities		29,811		27,651

		476,690		460,357

Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		320,397		308,302
Deferred investment tax credit		18,234		18,642
Regulatory tax liability		16,193		16,506
Customer advances for construction		82,213		79,243
Accrued retirement benefits		22,949		21,025
Risk management regulatory liability — net (Note 5)		8,112		—
Contract termination liabilities (Note 6)		35,064		34,847
Regulatory liabilities		172,139		171,330
Other		59,739		60,810

		735,040		710,705


TOTAL CAPITALIZATION AND LIABILITIES	$	4,891,962	$	4,883,540

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
	March 31,
	2005			2004
OPERATING REVENUES:
Electric	$	354,134		$	326,533

OPERATING EXPENSES:
Operation:
Purchased power		141,428			127,531
Fuel for power generation		55,640			49,355
Deferred energy costs disallowed		—			1,586
Deferral of energy costs-net		35,823			43,318
Other		51,099			39,722
Maintenance		16,955			19,956
Depreciation and amortization		30,402			28,739
Taxes:
Income tax benefit		(6,794	)		(11,453	)
Other than income		6,316			6,779

		330,869			305,533

OPERATING INCOME		23,265			21,000

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,490			657
Interest accrued on deferred energy		4,525			5,395
Disallowed merger costs		—			(3,961	)
Other income		6,913			5,740
Other expense		(1,576	)		(1,441	)
Income taxes		(3,102	)		(1,988	)

		10,250			4,402

Total Income Before Interest Charges		33,515			25,402

INTEREST CHARGES:
Long-term debt		41,529			37,151
Other		4,332			4,587
Allowance for borrowed funds used during construction		(4,313	)		(930	)

		41,548			40,808


NET LOSS	$	(8,033	)	$	(15,406	)

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	For the three months ended
	March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(8,033	)	$	(15,406	)
Non-cash items included in net (loss):
Depreciation and amortization		30,402			28,739
Deferred taxes and deferred investment tax credit		(3,692	)		(9,465	)
AFUDC		(7,803	)		(1,587	)
Amortization of deferred energy costs		46,673			46,499
Deferred energy costs disallowed		—			1,586
Other non-cash		6,020			(25,737	)
Changes in certain assets and liabilities:
Accounts receivable		13,876			18,332
Deferral of energy costs		(10,280	)		(8,576	)
Materials, supplies and fuel		2,905			(1,805	)
Other current assets		7,661			(5,664	)
Accounts payable		15,547			13,316
Escrow payment for terminating suppliers		—			(24,446	)
Other current liabilities		16,976			11,963
Other assets		(18,187	)		5,031
Other liabilities		3,054			(876	)

Net Cash from Operating Activities		95,119			31,904


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(140,095	)		(50,739	)
AFUDC and other charges to utility plant		7,803			1,587
Customer advances for construction		2,970			2,777
Contributions in aid of construction		(559	)		3,180

Net cash used for utility plant		(129,881	)		(43,195	)
Investments in subsidiaries and other property — net		1,924			(67	)

Net Cash used by Investing Activities		(127,957	)		(43,262	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt		(2,917	)		(2,174	)
Dividends paid		(19,852	)		(5,669	)

Net Cash used in Financing Activities		(22,769	)		(7,843	)


Net Decrease in Cash and Cash Equivalents		(55,607	)		(19,201	)
Beginning Balance in Cash and Cash Equivalents		243,323			144,897

Ending Balance in Cash and Cash Equivalents	$	187,716		$	125,696


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	28,650		$	28,416

Noncash Activities:
Transfer of Regulatory Asset	$	—		$	197,998

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)
(Unaudited)


	March 31,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,608,171	$	2,589,324
Less accumulated provision for depreciation		990,325		971,099

		1,617,846		1,618,225
Construction work-in-progress		52,724		50,480

		1,670,570		1,668,705


Investments and other property, net		987		999


Current Assets:
Cash and cash equivalents		90,154		19,319
Restricted cash (Note 1)		14,464		16,464
Accounts receivable less allowance for uncollectible accounts: 2005-$5,705; 2004-$5,296		127,765		142,359
Accounts receivable, affiliated companies		55,260		67,261
Deferred energy costs — electric (Note 1)		27,268		21,934
Deferred energy costs — gas (Note 1)		4,346		3,106
Materials, supplies and fuel, at average cost		35,292		31,335
Risk management assets (Note 5)		33,951		9,493
Deposits and prepayments for energy		20,733		31,676
Other		9,199		9,728

		418,432		352,675

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		142,874		151,039
Deferred energy costs — gas (Note 1)		1,699		2,491
Regulatory tax asset		111,642		112,545
Other regulatory assets		207,239		210,312
Risk management regulatory assets — net (Note 5)		—		3,118
Unamortized debt issuance expense		13,153		13,564
Other		14,187		8,872

		490,794		501,941

TOTAL ASSETS	$	2,580,783	$	2,524,320

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	715,871	$	705,395
Preferred stock		50,000		50,000
Long-term debt		973,623		994,309

		1,739,494		1,749,704

Current Liabilities:
Current maturities of long-term debt		22,398		2,400
Accounts payable		43,910		42,884
Accrued interest		24,872		9,604
Dividends declared		968		968
Accrued salaries and benefits		12,284		13,846
Deferred income taxes		16,995		17,138
Risk management liabilities (Note 5)		1,536		6,347
Accrued taxes		3,134		2,878
Contract termination liabilities (Note 6)		92,103		91,840
Other current liabilities		8,924		8,516

		227,124		196,421

Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		311,747		314,448
Deferred investment tax credit		23,015		23,422
Regulatory tax liability		23,569		24,069
Customer advances for construction		65,847		63,460
Accrued retirement benefits		46,759		41,558
Risk management regulatory liability — net (Note 5)		27,016		—
Contract termination liabilities (Note 6)		1,920		1,906
Regulatory liabilities		90,175		86,165
Other		24,117		23,167

		614,165		578,195

TOTAL CAPITALIZATION AND LIABILITIES	$	2,580,783	$	2,524,320

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
	March 31,
	2005			2004
OPERATING REVENUES:
Electric	$	227,010		$	201,841
Gas		67,538			59,476

		294,548			261,317

OPERATING EXPENSES:
Operation:
Purchased power		78,724			65,960
Fuel for power generation		54,362			53,802
Gas purchased for resale		53,480			47,917
Deferral of energy costs — electric — net		4,293			4,571
Deferral of energy costs — gas — net		(328	)		(1,407	)
Other		34,769			30,811
Maintenance		5,991			4,932
Depreciation and amortization		22,387			21,198
Taxes:
Income taxes		6,603			876
Other than income		4,748			5,015

		265,029			233,675

OPERATING INCOME		29,519			27,642

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		319			716
Interest accrued on deferred energy		1,583			1,154
Disallowed merger costs		—			(1,929	)
Other income		971			860
Other expense		(1,640	)		(1,313	)
Income (taxes) benefits		(452	)		323

		781			(189	)

Total Income Before Interest Charges		30,300			27,453

INTEREST CHARGES:
Long-term debt		17,307			18,868
Other		1,146			2,157
Allowance for borrowed funds used during construction and capitalized interest		(290	)		(1,243	)

		18,163			19,782


NET INCOME		12,137			7,671

Preferred Dividend Requirements		975			975

Earnings applicable to common stock	$	11,162		$	6,696

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)
(Unaudited)


	For the three months ended
	March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	12,137		$	7,671
Non-cash items included in net income:
Depreciation and amortization		22,387			21,198
Deferred taxes and deferred investment tax credit		(2,848	)		444
AFUDC		(609	)		(1,959	)
Amortization of deferred energy costs — electric		7,974			10,244
Amortization of deferred energy costs — gas		(466	)		2,015
Other non-cash		(1,641	)		(3,954	)
Changes in certain assets and liabilities:
Accounts receivable		26,595			3,063
Deferral of energy costs — electric		(5,143	)		(6,762	)
Deferral of energy costs — gas		18			(3,487	)
Materials, supplies and fuel		(3,957	)		6,696
Other current assets		11,472			3,677
Accounts payable		1,026			(7,481	)
Escrow payment for terminating supplier		—			(10,715	)
Other current liabilities		14,370			13,930
Other assets		(21,340	)		9,440
Other liabilities		27,930			1,785

Net Cash from Operating Activities		87,905			45,805


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(25,006	)		(19,917	)
AFUDC and other charges to utility plant		609			1,959
Customer advances for construction		2,387			2,127
Contributions in aid of construction		4,591			3,590

Net cash used for utility plant		(17,419	)		(12,241	)
Disposal of subsidiaries and other property — net		12			12

Net Cash used by Investing Activities		(17,407	)		(12,229	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings		—			(25,000	)
Change in restricted cash and investments		2,000			—
Retirement of long-term debt		(688	)		(694	)
Dividends paid		(975	)		(968	)

Net Cash from (used by) Financing Activities		337			(26,662	)


Net Increase in Cash and Cash Equivalents		70,835			6,914
Beginning Balance in Cash and Cash Equivalents		19,319			20,859

Ending Balance in Cash and Cash Equivalents	$	90,154		$	27,773


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	2,908		$	6,564

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) and Sierra Water Development Company (SWDC). SPC is a discontinued operation, and as such, is reported separately in the financial statements. The consolidated financial statements of NPC include the accounts of NPC and its wholly-owned subsidiary, Nevada Electric Investment Company (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, 2004 (the “2004 10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the three months ended March 31, 2005, 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. Previously reported net income (loss) and shareholders’ equity were not affected by these reclassifications.

Revised Quarterly Information

The amounts previously reported in SPR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 differ from the amounts currently reported due to revisions to reflect the discontinued operations of SPC, as discussed in the 2004 10-K. Amounts were revised as shown in the table below (in thousands, except for earnings per share information):


	Originally			Adjustment for
	Reported			Discontinued			Revised
	March 31, 2004			Operations			March 31, 2004
Operating revenues	$	588,480		($	363	)	$	588,117
Operating income	$	45,560		$	526		$	46,086

Income (loss) from continuing operations	($	43,475	)	$	675		($	42,800	)
Loss from discontinued operations		—		($	675	)	($	675	)
Deficit applicable to common stock	($	44,450	)		—		($	44,450	)
Amount per share — basic and diluted:
Loss from continuing operations	($	0.37	)		—		($	0.37	)
Loss from discontinued operations		—		($	0.01	)	($	0.01	)
Deficit applicable to common stock	($	0.38	)		—		($	0.38	)

Deferral of Energy Costs

NPC and SPPC implemented deferred energy accounting on March 1, 2001. Beginning January 2004, the California Public Utility Commission (CPUC) issued its decision which re-instituted the Energy Cost Adjustment (ECAC) mechanism for

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 2004 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 March 31, 2005 (dollars in thousands):


	March 31, 2005
	NPC			SPPC			SPPC			SPR
Description	Electric			Electric			Gas			Total

Unamortized balances approved for collection in current rates
Electric — NPC Period 1	$	(47,610	)	$	—		$	—		$	(47,610	)
Electric — SPPC Period 1		—			1,692			—			1,692
Electric — NPC Period 2		46,789			—			—			46,789
Electric — SPPC Period 2		—			(1,260	)		—			(1,260	)
Natural Gas — Period 3		—			—			(1,082	)		(1,082	)
Natural Gas — Period 4		—			—			785			785
LPG Gas — Period 2		—			—			5			5
LPG Gas — Period 3		—			—			49			49
Unamortized balances approved for collection by PUCN
in Docket No. 03-11019 effective April 1, 2005		88,722			—			—			88,722
in Docket No. 04-11028 effective April 1, 2005		115,752			—			—			115,752
in Docket No. 04-1006 effective June 1, 2005		—			42,378			—			42,378
Balances pending PUCN approval		—			27,100			—			27,100
Cumulative CPUC balance		—			4,561			—			4,561
Balances accrued since end of periods submitted for PUCN approval		21,110			11,639			6,288			39,037
Claims for terminated supply contracts⁽¹⁾		240,039			84,032			—			324,071

Total	$	464,802		$	170,142		$	6,045		$	640,989


Current Assets
Deferred energy costs — electric	$	101,020		$	27,268		$	—		$	128,288
Deferred energy costs — gas		—			—			4,346			4,346
Deferred Assets
Deferred energy costs — electric		363,782			142,874			—			506,656
Deferred energy costs — gas		—			—			1,699			1,699

Total	$	464,802		$	170,142		$	6,045		$	640,989

(1)

Amounts related to claims for terminated supply contracts are discussed in Note 6 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies.

Restricted Cash and Investments

At March 31, 2005, restricted cash primarily represents cash restricted for 1) debt service payments for SPR’s $300 million convertible notes, discussed in Note 7, Long-Term Debt, of Notes to Financial Statements in SPR’s 2004 10-K, and 2) the aggregate $60 million collateral payments made by NPC and SPPC into escrow in connection with the stay of the Enron Judgment, as described in Note 6, Commitments and Contingencies of the Condensed Notes to Consolidated Financial Statements. The remaining amount consists of cash balances that SPR, NPC and SPPC are required to maintain to support their cash management activities due to their financial condition.

Stock Compensation Plans

At March 31, 2005, SPR had several stock-based compensation plans, which are described more fully in Note 15, Stock Compensation Plans, of Notes to Financial Statements in SPR’s 2004 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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the disclosure only provisions of Financial Accounting Standards Board’s Statement of Financial Accounting Standards (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 deficit applicable to common stock would have changed to the pro forma amounts indicated below (dollars in thousands, except per share amounts):


		Three Months Ended March 31,
		2005			2004
Deficit applicable to common stock	As reported	$	(9,486	)	$	(44,450	)

Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	As reported		55			325

Less: Total stock employee compensation expense determined under fair value based methods, net of related tax effects	Pro forma		78			335


Pro forma deficit applicable to common stock	Pro forma	$	(9,509	)	$	(44,460	)


Basic and diluted deficit applicable to common stock per share	As reported	($	0.08	)	($	0.38	)
	Pro forma	($	0.08	)	($	0.38	)

Recent Pronouncements

The Securities and Exchange Commission (SEC) announced on April 14, 2005 that it was delaying implementation of SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R). Under SFAS 123R, registrants would have been required to implement the standard as of the beginning of the first interim or annual period that begins after June 15, 2005. SPR would have been permitted to follow the pre-existing accounting literature for the first and second quarters of 2005, but required to follow SFAS 123R for third quarter reports and thereafter. The SEC’s new rule allows SPR to implement SFAS 123R at the beginning of the next fiscal year that begins after June 15, 2005, or periods beginning December 31, 2005. The SEC’s new rule does not change the accounting required by SFAS 123R. Amounts that were previously shown in footnote disclosure by SPR will now be recognized in the income statement. SPR intends to utilize the services of its actuaries to value share-based compensation.

NOTE 2.SEGMENT INFORMATION

SPR’s Utilities operate three regulated business segments (as defined by SFAS 131, “Disclosure about Segments of an Enterprise and Related Information”); which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.

The net assets and operating results of SPC is reported as discontinued operations in the financial statements for 2005 and 2004. Accordingly, the segment information excludes financial information of SPC.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operational information of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which, the primary financial measure is business segment operating income. The accounting policies of the business segments are the same as those described in Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements in the 2004 10-K. Inter-segment revenues are not material (dollars in thousands).


Three Months Ended	NPC		SPPC		Total				��
March 31, 2005	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	354,134	$	227,010	$	581,144	$	67,538	$	292	$	648,974

Operating Income	$	23,265	$	23,864	$	47,129	$	5,655	$	6,164	$	58,948


Three Months Ended	NPC		SPPC		Total
March 31, 2004	Electric		Electric		Electric		Gas		Other			Consolidated
Operating Revenues	$	326,533	$	201,841	$	528,374	$	59,476	$	267		$	588,117

Operating Income	$	21,000	$	23,075	$	44,075	$	4,567	$	(2,556	)	$	46,086

NOTE 3.REGULATORY ACTIONS

Nevada Matters

Nevada Power Company 2004 Deferred Energy Case

On November 15, 2004, NPC filed an application with the Public Utility Commission of Nevada (PUCN) seeking repayment for purchased fuel and power costs accumulated between October 1, 2003 and September 30, 2004, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $116 million, with a carrying charge. The application requested that the 2004 Deferred Energy Accounting Adjustment (DEAA) recovery begin with the expiration of the 2002 DEAA recovery, which is expected to occur in May 2006 and for the 2004 DEAA recovery period to be 22 months.

The application also requested an increase to the going-forward base tariff energy rate (BTER).

In concert with this 2004 DEAA filing, NPC filed a petition with the PUCN requesting that other pending DEAA rate changes be synchronized to change on April 1, 2005 in order to stabilize rates and reduce the number of rate changes. On December 28, 2004, the PUCN issued an order approving a stipulation reached by all parties that allows NPC to defer previously approved DEAA rate changes until April 1, 2005 coincident with the DEAA rate change that will result from the 2004 DEAA case.

The combined effect of the requested synchronization of multiple rate changes (going forward BTER increase, 2001 DEAA expiration, 2003 DEAA initiation) resulted in a request for an overall rate decrease of 2.4%.

On February 22, 2005, a stipulation of the parties was filed with the PUCN resolving all issues in the case. The stipulation provides for an overall decrease of 0.6% in total rates with no disallowances. The PUCN approved the stipulation in total on March 16, 2005.

Sierra Pacific Power Company 2005 Deferred Energy Case

On January 14, 2005, SPPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between December 1, 2003 and November 30, 2004, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $28 million, with a carrying charge. The application requested that the 2005 DEAA recovery begin on June 1, 2005 together with the commencement of recovery of the 2004 DEAA balance both of which are coincident with the expiration of the 2002 and 2003 DEAA recovery. SPPC has requested a 24-month recovery period for the 2005 DEAA balance.

The application also requested an increase to the going-forward BTER.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The combined effect of the proposed synchronization of multiple rate changes (going forward BTER increase, 2002 and 2003 DEAA expiration, 2004 and 2005 DEAA initiation) resulted in a request for an overall rate increase of approximately 1.85%.

On March 30, 2005 SPPC filed an updated forecast of its going-forward BTER. If implemented, the new BTER, including the 2002 and 2003 DEAA expiration, and the 2004 and 2005 DEAA initiation, would result in an 8.73% overall rate increase.

On April 6, 2005, the PUCN Staff and the Bureau of Consumer Protection (BCP) filed written direct testimony in this case. The testimony recommended full recovery of the deferred balance after a $575 thousand reduction to reflect an accounting adjustment mutually agreed to by the parties. The PUCN Staff recommended adoption of the higher BTER rate that SPPC filed on March 30, 2005 while the BCP opposed the implementation of the higher BTER.

The PUCN held a hearing on April 18, 2005 and has indicated it will issue a ruling on May 17, 2005.

For further details of deferred energy cases see Note 3, Regulatory Actions of the Notes to Financial Statements, in the 2004 10-K.

NOTE 4. LONG -TERM DEBT

As of March 31, 2005, 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 2005, for the next four years and thereafter are shown below (dollars in thousands):


							SPR Holding
							Co. and			SPR
	NPC			SPPC			Other Subs.			Consolidated
2005	$	2,656		$	1,693		$	—		$	4,349
2006		6,509			52,400			—			58,909
2007		5,949			2,400			240,218			248,567
2008		7,066			322,400			—			329,466
2009		272,510			600			—			273,110

		294,690			379,493			240,218			914,401
Thereafter		1,993,505			617,250			635,000	⁽¹⁾		3,245,755

		2,288,195			996,743			875,218			4,160,156
Unamortized (Discount Amount)		(9,331	)		(722	)		(5,725	)		(15,778	)

Total	$	2,278,864		$	996,021		$	869,493		$	4,144,378

(1)

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 approximately $244 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.

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

Financing Transactions (SPR — Holding Company)

On April 15, 2005, SPR commenced an offer to exchange new Premium Income Equity Securities (PIES) plus an exchange fee of $0.125 in cash for each old PIES tendered for exchange. The exchange offer will expire on or about May 18, 2005, unless extended or terminated by SPR pursuant to the conditions for the exchange offer. SPR’s new PIES will be similar to its old PIES except the new PIES will (i) allow the remarketing of the senior notes that are associated with the new PIES prior to the earliest remarketing date for the old PIES, (ii) provide for more flexible remarketing terms, and (iii) allow certain terms of the senior notes to be modified upon their remarketing, including the maturity date of the senior notes, the redemption provisions, the interest payment dates and the addition of covenants applicable to the senior notes. There can be no assurance that a significant amount of SPR’s old PIES will be tendered in the exchange or that, even if a significant amount of old PIES are tendered in the exchange, SPR will be able to remarket the senior notes associated with the new PIES on favorable terms.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 5. DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC, and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, 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. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard.

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.

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. Due to deferred energy accounting under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized (dollars in millions):


	March 31,									December 31,
	2005									2004
	SPR			NPC			SPPC			SPR		NPC		SPPC
Risk management assets	$	61.0		$	27.0		$	34.0		$	14.6	$	5.1	$	9.5
Risk management liabilities	$	2.1		$	0 .6		$	1.5		$	9.9	$	3.6	$	6.3
Risk management regulatory assets (liabilities)	$	(35.1	)	$	(8.1	)	$	(27.0	)	$	6.7	$	3.6	$	3.1

Also included in risk management assets were $23.7 million, $18.3 million, and $5.4 million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at March 31, 2005.

NOTE 6. 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 pollution controls and other capital investments 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.

On October 20, 2004, the CPUC issued a proposed decision which, among other things, directed SCE to continue negotiations with the Tribes regarding post-2005 coal and water supply, and directed SCE to conduct a study of potential alternatives to Mohave. Because coal and water supplies necessary for long-term operation of Mohave have yet to be secured, 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.

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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 approximately $33 million, of which, approximately $20 million has been spent through 2004. Estimated total capital expenditures in 2005 and 2006 are approximately $6 million and $3 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.

In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. Monitoring, recordkeeping and other reporting items including maintenance records, operating logs, recorded oil/coal data, and other information pertaining to the sources identified in the Title V permit were requested by NDEP. NPC has provided information in connection with this and subsequent requests. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC that it may not be in compliance with some elements of its Title V permit, and on December 2, 2004 issued Notices of Alleged Violation (NOAVs). NPC is continuing to provide information to NDEP as requested, and is engaged in discussions with NDEP in an effort to resolve the compliance issues identified in the NOAVs. Because no penalty has been specified by NDEP, and discussions are continuing, management cannot at this time reasonably estimate the amount of any potential penalties that may ultimately be assessed in connection with the alleged violations.

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. NPC’s position is 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 approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Currently, management is continuing to evaluate various options including reclamation and sale.

Sierra Pacific Power Company

In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which has completed site investigations and with 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 work to dismantle the buildings and dispose of the debris and impacted soil is currently underway, and is expected to be complete in mid-2006. While the final cost to complete the work is not yet definite, SPPC’s share of the cost is not expected to be material.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Litigation

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

Brief Overview

Currently the Utilities are involved in a number of court cases and hearings involving Enron Power Marketing, Inc (Enron). The cases are as follows: U.S Bankruptcy Court for the Southern District Court of New York (Bankruptcy Court), U.S. District Court for the Southern District of New York (U.S. District Court); Federal Energy Regulatory Commission (FERC) hearings consisting of the FERC Early Termination, FERC Revocation Show Cause Proceeding and the FERC Gaming and Show Cause Proceeding. See details of the court cases and hearings below.

In 2003, based on the Judgment entered by the Bankruptcy Court (Judgment), NPC and SPPC recorded contract termination liabilities of $235 million and $103 million, including prejudgment interest of $27.8 million and $12.4 million, respectively. Additionally, in order to stay execution of the Judgment, NPC and SPPC have posted into escrow $186 million and $92 million, respectively, of General and Refunding Mortgage Bonds and $49 million and $11 million, respectively, in cash as of December 31, 2004. On October 10, 2004, in response to our appeal of the Judgment, the U.S. District Court rendered a decision vacating an earlier judgment by the Bankruptcy Court against the Utilities in favor of Enron, and remanded the case back to the Bankruptcy Court for fact-finding. Furthermore, the U.S. District Court held that the pre-judgment interest should have been calculated at the present value rate, rather than at the rate of 1% per month used by the Bankruptcy Court.

Based on the U.S. District Court’s decision, the Utilities reversed the accrued interest included in contract termination liabilities by approximately $40 million for the year ended 2004. Although the Judgment entered by the Bankruptcy Court has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron, discussed below, will remain in place through the pendency of all remands and appeals of the Judgment. If the Utilities are ultimately 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 amount not permitted would be charged as a current operating expense.

A description of the legal proceedings leading up to U.S. District Court’s order to vacate follows, along with a discussion of all pending matters related to the Enron litigation.

Bankruptcy Court Judgment

On June 5, 2002, 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 for termination payments Enron claimed it was owed under purchased power contracts with the Utilities. Enron sought liquidated damages in the amount of approximately $216 million from NPC and $93 million from SPPC based on assertions by Enron that it had contractual rights under the Western Systems Power Pool Agreement (WSPPA) to terminate deliveries to the Utilities. Enron based its assertion on a claim 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

thousand 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.

On April 5, 2004, 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 and 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. 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.

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

On 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 the Bankruptcy Court’s order with respect to these payments, and no final ruling has been made by the Bankruptcy Court.

Appeal of Bankruptcy Court Judgment to U.S. District Court

On October 1, 2003, the Utilities filed a Notice of Appeal from the Judgment with the U.S. District Court. 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 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.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The U.S. District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The U.S. 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 U.S. District Court decision also provided that Enron could, 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. 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 U.S. District Court rulings with respect to the Utilities’ affirmative defenses and counterclaims 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. This motion did not relate to Enron’s claims against the Utilities, which the U.S. District Court addressed in its October 10, 2004 decision described above. On December 23, 2004, the U.S. District Court ruled on this motion, affirming the dismissal of the Utilities’ affirmative defenses and counterclaims on the grounds that they were barred under the filed rate doctrine. However, the U.S. District Court ruled in favor of the Utilities on the calculation of pre-judgment interest.

FERC Early Termination Case

On October 6, 2003, the Utilities filed a Complaint with FERC requesting the opportunity to develop a record regarding three issues: (a) whether Enron exercised reasonable discretion in terminating its various purchased power contracts with the Utilities; (b) whether FERC should exercise its authority to find that Enron is not entitled to collect termination payment profits; and (c) whether Enron should be otherwise denied the authority to collect such payments because to do so would be contrary to the public interest.

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 27, 2004, Enron filed a motion in the Bankruptcy Court to enjoin the Utilities from participating in the FERC Early Termination Case. The disposition of this motion is described below.

Bankruptcy Court Injunction and Order Setting Trial

After the U.S. District Court issued its October 10, 2004 ruling, Enron renewed its motion with the Bankruptcy Court seeking to enjoin the Utilities from proceeding in the FERC Early Termination Case. On December 3, 2004, the Bankruptcy Court enjoined the Utilities from further prosecution of the scheduled hearing in the FERC proceeding. The Utilities have appealed this decision and are seeking a stay of the trial in Bankruptcy Court pending the outcome of the FERC Early Termination Case. The trial is currently set for July 11, 2005. The Utilities are unable to predict the outcome of these proceedings at this time.

FERC Revocation Show Cause Proceeding

In March 2003, FERC instituted a “Show Cause” proceeding involving whether Enron’s market-based rate authority should be revoked in light of Enron’s engagement in illicit trading activities. The Utilities intervened in the FERC’s proceeding against Enron. On June 25, 2003, FERC removed Enron’s market-based rate authority, but only on a prospective basis. The Utilities filed a request for rehearing, along with certain other parties. On October 16, 2003, FERC changed the nature of the proceeding, thereby prohibiting further active participation by the interveners (including the Utilities). On December 15, 2003, the Utilities filed an appeal in the United States Circuit Court of Appeals for the District of Columbia (D.C. Circuit) concerning these two actions. The appeals have been consolidated with a number of other appeals of FERC’s decisions, and the matter is pending. The D.C. Circuit has yet to establish a briefing schedule and there is no current time line for argument or a decision in the case.

FERC Gaming and Partnership Show Cause Proceeding

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

proceeding. The Utilities have joined a coalition of other Western Parties and on August 4, 2004, sought clarification that remedies other than disgorgement might be available. On March 11, 2005, the FERC issued an order clarifying issues to be covered in the administrative trial scheduled to begin June 13, 2005. In that order, the FERC stated that Enron’s profits under the terminated power contracts fell within the scope of that proceeding. The trial is currently set for September 7, 2005. The Utilities are unable to predict the outcome of the trial at this time.

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 are contesting the amounts paid for power actually delivered by these suppliers 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 was held on December 8, 2004 and a decision is pending. The Utilities are unable to predict the outcome of this appeal at this time.

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 management is not able 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 (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 District

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Court granted the stay for another 90 days. At the February 28, 2005 status conference, the Judge lifted the stay and ordered the case to go forward. The parties will meet to set the discovery and trial schedule. On February 28, 2005, NPC filed a motion for summary judgment. MSCG filed its own summary judgment motion on March 17, 2005. A hearing on the motions has been set for June 6, 2005. At this time, NPC is unable to predict the outcome or timing of the District Court complaint.

El Paso Merchant Energy

In September 2002, El Paso Merchant Energy (EPME) terminated all forward contracts for energy with NPC for alleged defaults under the WSPPA consisting of alleged failure to pay full contract price for power under NPC’s “delayed” payment program which extended from May 1 to September 15, 2002. In October 2002, EPME asserted a claim against NPC for $29 million in damages representing $19 million unpaid under contracts for delivered power during the period May 15 to September 15, 2002, together with approximately $10 million in alleged mark to market damages for future undelivered power. The amount presently claimed by EPME is $42 million, including interest. NPC alleges that EPME’s termination resulted in net payments due to NPC under the WSPPA for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. The precise amount due would depend on the manner in which the termination payments are calculated.

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. 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 and the case is set for trial to commence in September 2005. At this time, NPC is unable to predict either the outcome or timing of a decision in this matter.

Peabody Western Coal Company

NPC owns an 11%, 255 MW interest in the Navajo Generating Station (Navajo) located in Northern Arizona. Besides NPC, the Salt River Project (Salt River), Arizona Public Service Company, Los Angeles Department of Water and Power, and Tucson Electric Power Company (together the Joint Owners), are partners in Navajo, which includes three coal-fired electrical generating units operated by Salt River.

In January 2005, the Joint Owners were served with a complaint from Peabody Western Coal Co. (Peabody), filed in Missouri State Court in St. Louis (Cause No. 042-08561). Peabody asserts claims against the Joint Owners seeking reimbursement of royalties and other costs and breach of the coal supply agreement.

As operating agent for the project, Salt River has engaged counsel and is defending the suit on behalf of the Joint Owners. On February 20, 2005, the Joint Owners filed Notice of Removal of the compliant to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a Motion to remand the case to state court in St. Louis, Missouri. The Joint Owners are presently conducting discovery in connection with the Motion. NPC believes Peabody’s claims are without merit and intends to contest them.

Sierra Pacific Power Company

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.

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 the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs. The current estimate to rebuild the diversion dam, if management decides to proceed, 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. Management has not recorded a loss contingency for the cost to rebuild the dam as it believes its overall exposure is insignificant.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

At March 31, 2005, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” were approximately $247 million and $94 million, respectively, of charges 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 March 31, 2005, were approximately $240 million and $84 million, respectively, of charges 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 effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

Regulatory Contingency

Nevada Power Company

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. NPC’s Integrated Resource Plan (IRP) accepted by the PUCN in November 2003, assumes the Plant will be unavailable after December 31, 2005. In addition, in its General Rate Case filed on October 1, 2003, NPC requested that the PUCN authorize a higher depreciation rate be applied to Mohave in order to recover the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN. While the PUCN did not approve higher depreciation rates, they did authorize the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its shutdown with recovery of any accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave through rates.

If the coal and water supply issues at Mohave are ultimately resolved the owners, including NPC, would still be required to install the pollution control equipment, as discussed in the Environmental section, to operate the generating facility. The installation of this equipment would still require the temporary shutdown of the facility. Furthermore the owners, including NPC, are evaluating the use of alternative fuels to operate the Mohave generating facility in the event the coal and water supply issues are not resolved. The use of alternative fuels would also cause the facility to be shutdown temporarily. NPC would seek recovery of any future costs to bring the facility into operation through a future rate case. Due to these factors there is uncertainty as to whether Mohave will operate post December 2005.

In the event Mohave is permanently shutdown, NPC will have to evaluate the plant in accordance with SFAS No. 90, “Accounting for Abandonments and Disallowances of Plant Costs” (SFAS 90). If NPC is prohibited from continued recovery of Mohave in the future, the asset may be deemed impaired under SFAS 90. If the asset is deemed impaired there could be a material effects on NPC’s and SPR’s financial position, results of operations, and future cash inflows. As of March 31, 2005, the net book value of Mohave is approximately $38 million.

NOTE 7. EARNINGS PER SHARE (EPS) (SPR)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, the non-employee director stock plan and dividend participation rights associated with the convertible debt. However, due to net losses for the periods ended March 31, 2005 and 2004 these items are anti-dilutive. Accordingly, diluted EPS for these periods are computed using the weighted average shares outstanding before dilution.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SPR currently has outstanding $300 million in 7.25% convertible notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments on a 1:1 basis for dividends paid to 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. See the 2004 10-K, Note 7, Long-Term Debt, for Discussion of the Convertible Notes.

EITF 03-6 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, if the effect is dilutive. SPR adopted EITF 03-6 for financial statements issued after March 31, 2004. However, due to net losses for the three months ended March 31, 2005 and 2004 the effect of the participating securities are anti-dilutive, as such they have not been included in basic or diluted earnings per share.

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


	Three Months
	Ended March 31,
Basic and Diluted EPS¹	2005			2004
Numerator ($000)
Loss from continuing operations	$	(8,516	)	$	(42,800	)
Income / (Loss) from discontinued operations	$	5		$	(675	)
Deficit applicable to common stock	$	(9,486	)	$	(44,450	)

Denominator
Weighted average number of common shares outstanding		117,549,912			117,239,947


Per-Share amount
Loss from continuing operations	$	(0.07	)	$	(0.37	)
Loss from discontinued operations		—		$	(0.01	)
Deficit applicable to common stock	$	(0.08	)	$	(0.38	)

1) The denominator used for diluted EPS calculation does not include stock equivalents for stock options, restricted and performance shares issued under executive long-term incentive plan options under the non-employee Director stock plan and employee stock purchase plan, for periods ending March 31, 2005 and 2004, due to their anti-dilutive effect. The amounts for periods ending March 31, 2005 and 2004 that would be included in the calculation would be 412,041 and 185,882 shares, respectively.

The denominator also does not include stock equivalents resulting from the conversion of SPR’s PIES and options issued under the Nonqualified stock option plan for periods ending March 31, 2005 and 2004, due to conversion prices being higher than market prices for all periods. The amounts that would be included in the calculation, if the conversion and exercise prices were met, would be 17.3 million shares for SPR’s PIES for both periods, and 1.1 million and 1.3 million shares for options under the Nonqualified stock option plan for periods ending March 31, 2005 and 2004 respectively.

NOTE 8. GOODWILL AND OTHER MERGER COSTS

SPR’s Consolidated Balance Sheet as of March 31, 2005 included approximately $4 million of goodwill assigned to SPR’s unregulated operations and approximately $19 million of goodwill assigned to SPPC’s regulated gas business. The goodwill assigned to the regulated gas business is subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulations”, which permits SPPC to capitalize certain costs that may be recovered through rates. 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 approximately $4 million of goodwill assigned to SPR’s unregulated operations were subject to impairment review under the provisions of SFAS No. 142, “Accounting for Goodwill, Other Intangible Assets.”

SFAS No.142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was developed for SPR’s unregulated businesses (TGPC and LOS) to determine the fair value of each reporting unit as of March 31, 2005. As a result, goodwill assigned to TGPC and LOS was determined not to be impaired.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 9. PENSION AND OTHER POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other post-retirement costs for the three months ended March 31, 2005 and 2004, follows. This summary is based on a September 30 measurement date (dollars in thousands):


							Other Post-retirement
	Pension Benefits						Benefits
	2005			2004			2005			2004
Service cost	$	4,620		$	4,497		$	820		$	779
Interest cost		8,062			7,568			2,465			2,382

Expected return on plan assets		(9,042	)		(7,658	)		(903	)		(1,034	)
Amortization of prior service cost		428			428			16			16

Amortization of Transition Obligation		—			—			242			242
Amortization of net (gain)/loss		1,614			2,243			1,059			1,157


Net periodic benefit cost	$	5,682		$	7,078		$	3,699		$	3,542

As disclosed in Note 12, Retirement Plan and Post-retirement Benefits, of the 2004 10-K, SPR, NPC and SPPC does not expect to make a pension contribution and expect to contribute approximately $200 thousand for post-retirement benefits for the year 2005. As of March 31, 2005, there had been no changes to the 2005 estimated employer contribution amounts disclosed.

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

Forward-Looking Statements and Risk Factors

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

	(1)	a requirement to pay 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 maintain access to 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 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 and credit agreements, the Enron Bankruptcy Court’s order, their regulatory order from the PUCN, 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)	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;

	(7)	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;

	(8)	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;

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

	(10)	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;

	(11)	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;
	(12)	industrial, commercial, and residential growth in the service territories of the Utilities;

	(13)	the financial decline of any significant customers;

	(14)	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;

	(15)	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;

	(16)	changes in environmental regulations laws or regulation, including the imposition of significant new limits on mercury and other emissions from coal-fired power plants;

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

	(18)	future economic conditions, including inflation rates and monetary policy;

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

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

	(21)	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:

	o	Results of Operations

	o	Analysis of Cash Flows

	o	Liquidity and Capital Resources

	o	Regulatory Proceedings (Utilities)

	o	Recent Pronouncements

SPR’s Utilities operate three regulated business segments: 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 accordingly 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. SPR intends to continue to focus on improving earnings and operating cash flows, controlling costs and reducing debt while working to restore an investment grade credit rating.

The population growth within the Utilities’ service territory has been and is projected to continue to grow at a rapid rate. The population growth has been driven by economic expansion throughout the state, with the gaming industry in Las Vegas being the most significant component.

The Utilities are exposed to a variety of risks inherent in their commercial operations, including risks from energy supply, credit, facilities, information and control systems, environmental, and accidental loss. The Utilities address these risks in a variety of ways. Energy risk is addressed through commitments to generation and transmission and to longer-term energy supply contracts. These commitments are subject to an approval process by the Public Utilities Commission of Nevada (PUCN), and in the case of SPPC, the Californmia Public Utility Commission (CPUC) through resource planning regulations. Other multi-year risks are addressed, in part, through insurance policies as well as the Utilities’ strategic planning processes. Shorter-term risks are also addressed through insurance and through annual budgets, key performance indicators and prioritized objectives.

In addition to customer growth, loads and resulting revenues are affected by weather, rate changes, and customer usage patterns. Changes in energy usage by the Utilities fluctuate primarily as a result of seasonal weather conditions. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning, while SPPC’s electric system peak typically occurs in the summer, with a winter peak nearly as high as the summer peak. Therefore, the Utilities’ operating revenues and associated expenses are not generated or incurred evenly throughout the year.

During the first quarter of 2005, NPC’s revenues increased from the same period in 2004 as a result of higher rates that went into effect in the second quarter of 2004, and additional customers compared to the first quarter of 2004. This increase was partially offset by milder weather in the first quarter in 2005 as compared to 2004, resulting in a decrease in customer usage. NPC’s 2005 first quarter net loss was smaller than the loss in 2004 primarily due to increased operating revenue partially offset by higher operating expenses, depreciation and amortization, and interest charges.

SPPC’s electric and gas revenues also increased in the first quarter of 2005 from the same period in 2004 as a result of higher rates that went into effect in the second and fourth quarters of 2004, respectively, additional customers and increased customer usage compared to the first quarter of 2004. SPPC’s net income increased for the first quarter of 2005 as compared to the first quarter of 2004 primarily due to increased operating revenue partially offset by higher operating and maintenance expenses, and higher depreciation and amortization.

SPR’s loss from continuing operations decreased in the first quarter of 2005 as compared to 2004 as a result of a first quarter 2004 write-off of goodwill associated with the 1999 merger of SPR and NPC and tender fees paid in 2004 in connection with extinguishment of certain debt, neither of which recurred in 2005.

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. In February 2005, the PUCN approved a settlement agreed to by all parties in NPC’s deferred energy case initially filed in November 2004. The settlement resolved all issues in the case and resulted in no disallowances. SPPC filed for recovery of its deferred energy costs in January 2005. The staffs of the PUCN and the Bureau of Consumer Protection (BCP) filed testimony recommending full recovery of the deferred balance. Hearings were held in April 2005 and a decision by the PUCN is expected in the latter part of May 2005. The Utilities are required to file for annual rate adjustments to provide recovery of

their fuel and purchased power costs. They are also required to file rate cases every two years to adjust general rates that include its cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. The Utilities remain committed to maintaining a positive relationship with our regulators for the benefit of all stakeholders.

Significant Business Issues

SPR and the Utilities face a number of key business issues in 2005, including, among other things: the ongoing litigation involving Enron, improving our debt profile, management of our energy risk, pursuing strategic initiatives to reduce our reliance on external power supplies, and legislative initiatives. Details relating to the discussion below can be found in the 2004 10-K Notes to the Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Enron Litigation

Currently, the Utilities are involved in five court cases and hearings involving Enron Power Marketing, Inc (Enron) enumerated as follows: U.S. Bankruptcy Court for the Southern District Court of New York (Bankruptcy Court), U.S. District Court for the Southern District of New York (U.S. District Court); Federal Energy Regulatory Commission (FERC) hearings consisting of the FERC Early Termination, FERC Revocation Show Cause Proceeding and the FERC Gaming and Show Cause Proceeding. See details of the court cases and hearings in Note 6, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Based on the U.S. District Court’s decision, the Utilities reversed the accrued interest included in contract termination liabilities by approximately $40 million for the year ended 2004. Although the Judgment entered by the Bankruptcy Court has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron will remain in place through the pendency of all remands and appeals of the Judgment. If the Utilities are ultimately required to pay part or all of the amounts accrued, the Utilities will pursue recovery of the payments through future deferred energy filing. To the extent that the Utilities are not permitted to recover any portion of these costs through a deferred energy filing, the amount not permitted would be charged as a current operating expense.

A trial date has been set for July 11, 2005 before the Bankruptcy Court. A description of the legal proceedings leading up to the U.S. District Court’s order to vacate along with a discussion of all pending matters related to the Enron litigation are detailed in Note 6, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Improved Debt Profile

In 2005, management intends to seek opportunities to refinance existing debt at lower interest rates and to extend the maturity dates of certain indebtedness in order to obtain interest cost savings and to better manage SPR’s and the Utilities’ indebtedness profiles. On April 15, 2005, SPR commenced an offer to exchange new Premium Income Equity Securities (PIES) for its previously issued PIES. Although the new PIES are similar to the old PIES, the new PIES will allow for more flexible remarketing terms that will increase the likelihood that SPR will be able to achieve a successful remarketing of the senior notes that are a component of the new PIES on economically attractive terms. In addition, the terms of the new PIES will allow SPR to extend the November 15, 2007 maturity date of the senior notes that are a component of the new PIES to a maximum term ending November 15, 2016. Details of the PIES transaction is discussed later under SPR Liquidity and Capital Resources.

Management is focused on returning to investment grade ratings.

Management of Energy Risk

The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also maintain extensive transmission systems that allow the Utilities to

move energy to meet customers’ needs. The Utilities’ exposure to energy markets has exacerbated the capacity and energy needs of our customers compared with its ownership and contractual call on power generating assets. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk — the prospect that energy supplies will not be sufficient to fulfill customer requirements.

The Utilities systematically manage and control each of the energy-related risks through three primary vehicles – organization and governance, energy risk management programs, and energy risk control practices.

The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.

The Utilities follow an approved energy supply plan that governs the purchase and sale of fuel and wholesale power and the associated transmission or transportation services in order to mitigate these risks. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for hedging in conjunction with energy purchases and sales are also used to mitigate these risks.

Strategic Initiatives to Reduce Reliance on External Power Supplies

In 2004, the Utilities announced a strategy to continue reducing their exposure to volatile swings in power prices by investing in additional generating facilities.

In October 2004, after PUCN approval, NPC purchased a partially constructed nominally rated 1,200 MW (megawatts) natural gas-fired combined cycle power plant from Duke Energy. NPC was able to finance the Chuck Lenzie Generating Station (Lenzie) project at lower rates than projected. In addition, the PUCN approved an incentive return on equity (ROE) equal to 2% above the authorized ROE on construction costs of the facility, plus an additional 1% incentive for early completion and production. NPC entered into a contract with Fluor Enterprises to complete construction of the Lenzie project. The revised completion of Unit 1 of the facility is targeted for December 2005 and March 2006 is the targeted completion date for Unit 2. Total costs to acquire and complete construction of the facility are estimated at approximately $545 million, which includes $182 million paid to Duke for the facility.

SPPC received PUCN approval of the Integrated Resource Plan to move forward with permitting and conceptual engineering to build a 500-megawatt, natural gas-fired, combined cycle electric generating plant at the Tracy plant site, east of Reno. There will be an assessment of coal-fired generation alternatives for the Valmy Generating Station, including expansion and possible construction of a future generating unit.

Legislative Initiatives

The Nevada State Legislature (the “Legislature”) is currently in session. The Legislature is considering several bills that could have an impact on the Utilities’ business, two of which are Senate Bills 188 (SB 188) and 256 (SB 256).

SB 188 would revise the provisions governing the portfolio standard for renewable energy and energy from a qualified energy recovery process. If enacted, this legislation will allow a provider of electric service to receive credits toward meeting the portfolio standard if the provider pays part of the costs of certain energy efficiency measures that save electricity. For calendar years 2005 through 2009, not more than 25 percent of the renewable portfolio standard may be based on energy efficiency programs.

The Legislature is also considering legislation that would revise certain provisions relating to the timing of rate cases. If enacted, SB 256 would establish schedules for the filings of general rate and deferred energy clearance applications that are different from current schedules, and would allow rate design in deferred energy cases if rates were decreasing.

Because of the uncertainty relating to the proposed legislation, management is not able to evaluate the potential impact of these initiatives on SPR or the Utilities.

SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Consolidated)

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later. The Holding Company’s (stand alone) operating results included approximately $19.6 million and $34.3 million of interest costs for the three months ended March 31, 2005 and 2004, respectively.

During the three months ended March 31, 2005, SPR incurred a loss applicable to common stock of approximately $9.5 million compared to an approximate $44.5 million loss applicable to common stock for the same period in 2004. The decrease in SPR’s consolidated loss during the three months ended March 31, 2005 compared to the same period in 2004 was primarily due to the following charges recorded at the Holding Company during the three months ended March 31, 2004 (before income taxes):

	•	a non-cash goodwill impairment charge of approximately $11.7 million;

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

	•	a charge of approximately $12.6 million of tender fees associated with the early extinguishment of SPR’s 8³/4% Senior Unsecured Notes due 2005.

See the 2004 10-K for additional discussion of the above items.

Neither SPR nor SPPC paid or declared a common dividend in the quarter ended March 31, 2005. NPC paid a common stock dividend of $19.9 million to SPR. SPPC declared $975 thousand in dividends to holders of its preferred stock in the quarter ended March 31, 2005.

On May 3, 2005 NPC declared a dividend to SPR of approximately $5.4 million and SPPC declared for the second quarter $975,000 in dividends to holders of its preferred stock.

ANALYSIS OF CASH FLOWS

SPR’s consolidated net cash flows increased for the three months ended March 31, 2005 compared to the same period in 2004, primarily as a result of an increase in cash from operating and financing activities offset by an increase in cash used in investing activities. Cash flows for operating activities were higher in the 2005 period due to energy related rate increases that became effective in the second quarter of 2004, which was the result of the Utilities’ General and Deferred Energy Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash from operating activities for the first quarter of 2005 compared to the same period in 2004 was a result of the $35 million escrow payment made by the Utilities to Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of revolving credit facilities and improved positions in hedging activity due to increasing energy prices. The increase in cash used by investing activities was a result of construction at NPC for the Lenzie project. The increase in cash from financing activities in the first quarter of 2005, when compared to the same period in 2004, was primarily due to the repayment of $25 million in short-term borrowings in March 2004.

LIQUIDITY AND CAPITAL RESOURCES

SPR, on a stand-alone basis, had cash and cash equivalents of approximately $4.5 million at March 31, 2005, which does not include restricted cash and investments of approximately $10.9 million representing collateral for payment of interest up to and including the August 14, 2005 payment in connection with SPR’s 7.25% Convertible Notes due 2010.

SPR paid approximately $30.8 million of debt service obligations on its existing debt securities during the first quarter of 2005. Included in these payments was approximately $10.9 million previously provided for at the time the Convertible Notes were issued as discussed above. Excluding interest on SPR’s 7.25% Convertible Notes, SPR has approximately $30.7 million payable of debt service obligations remaining during 2005, which SPR expects to meet through the payment of dividends by the Utilities to SPR.

During the three months ended March 31, 2005, there were no material changes to contractual obligations as set forth in SPR’s 2004 10-K.

Dividends from Subsidiaries

Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. 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 agreements entered into by the Utilities, restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are discussed in detail in the 2004 10-K, Note 9, Dividend Restrictions of the Notes to Financial Statements, and remain unchanged from their description in the 2004 10-K.

As of March 31, 2005, each Utility was able to pay dividends, subject to a cap, under the most restrictive test in its financing agreements; however, the total amount of dividends that the Utilities can pay to SPR under their financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under their financing agreements is greater than the amount that the Utilities can pay under their other dividend restrictions. The Utilities have agreed, under the terms of a stipulation with Enron, that they will not pay dividends to SPR other than for SPR’s debt service obligations and current operating expenses, which amount (discussed above) is substantially less than the maximum amounts the Utilities can pay as dividends under their financing agreement dividend restrictions. As of May 3, 2005, NPC had paid $19.9 million in dividends to SPR and had declared additional dividends of approximately $5.4 million in 2005 and SPPC had not declared or paid any dividends to SPR in 2005.

Financing Transactions (SPR – Holding Company)

On April 15, 2005, SPR commenced an offer to exchange new Premium Income Equity Securities (PIES) plus an exchange fee of $0.125 in cash for each old PIES tendered for exchange. The exchange offer will expire on or about May 18, 2005, unless extended or terminated by SPR pursuant to the conditions for the exchange offer. SPR’s new PIES will be similar to its old PIES except the new PIES will (i) allow the remarketing of the senior notes that are associated with the new PIES prior to the earliest remarketing date for the old PIES, (ii) provide for more flexible remarketing terms, and (iii) allow certain terms of the senior notes to be modified upon remarketing, including the maturity date of the senior notes, the redemption provisions, the interest payment dates and the addition of covenants applicable to the senior notes. There can be no assurance that a significant amount of SPR’s old PIES will be tendered in the exchange or that, even if a significant amount of old PIES are tendered in the exchange, SPR will be able to remarket the senior notes associated with the new PIES on favorable terms.

Limitations on Indebtedness

The terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014 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 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 the Senior 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 Senior Notes remain investment grade. As of March 31, 2005, SPR, NPC and SPPC would have been able to issue approximately $550 million of additional indebtedness on a consolidated basis, assuming an interest rate of 8 5/8%, per the requirement stated in number 1 above.

Cross Default Provisions

None of the Utilities’ financing agreements contain a cross-default provision that would result in an event of default by that Utility upon an event of default by SPR or the other Utility under any of their respective financing agreements. Certain of SPR’s financing agreements, however, do contain cross-default provisions that would result in event of default by SPR upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of SPR and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity 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 summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Resources – Liquidity and Capital Resources (SPR Consolidated),” and remain unchanged from their description in the 2004 10-K.

Judgment Related Defaults

Certain of the Utilities’ financing agreements contain judgment default provisions that provide for an event of default if a final, unstayed judgment is rendered against the Utility and remains undischarged after 60 days. The judgment default provisions in the Utilities’ various financing agreements and the consequences of a judgment default for either of the Utilities are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Resources – Liquidity and Capital Resources (SPR Consolidated).” There have been no changes to the judgment default provisions as described in the 2004 10-K.

Effect of Holding Company Structure

As of March 31, 2005, 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 March 31, 2005, SPR, NPC, SPPC, and their subsidiaries had approximately $4.1 billion of debt and other obligations outstanding, consisting of approximately $2.3 billion of debt at NPC, approximately $1 billion of debt at SPPC and approximately $0.8 billion of debt at the holding company and other subsidiaries. Additionally, SPPC had $50 million of outstanding preferred stock. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended March 31, 2005, NPC incurred a net loss of approximately $8 million compared to a net loss of approximately $15.4 million for the same period in 2004. NPC paid a common stock dividend of $19.9 million to SPR in the three months ended March 31, 2005 and declared a dividend of approximately $5.4 million on May 3, 2005.

Gross margin is presented by NPC in order to provide information by segment 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 components of gross margin were (dollars in thousands):


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Operating Revenues:
Electric	$	354,134	$	326,533		8.5	%

Energy Costs:
Purchased power		141,428		127,531		10.9	%
Fuel for power generation		55,640		49,355		12.7	%
Deferred energy costs-disallowed		—		1,586		N/A
Deferral of energy costs-electric-net		35,823		43,318		-17.3	%

		232,891		221,790		5.0	%


Gross Margin	$	121,243	$	104,743		15.8	%

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


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Electric Operating Revenues
Residential	$	143,005	$	128,488		11.3	%
Commercial		82,755		75,254		10.0	%
Industrial		103,332		94,398		9.5	%

Retail revenues		329,092		298,140		10.4	%
Other¹		25,042		28,393		-11.8	%

Total Revenues	$	354,134	$	326,533		8.5	%


Retail sales in thousands of megawatt-hours (MWh)		3,788		3,762		0.7	%

Average retail revenue per MWh	$	86.88	$	79.25		9.6	%

Primarily wholesale, as discussed below.

NPC’s retail revenues were higher for the three months ended March 31, 2005, compared to the same period in the prior year, due to increases in the number of residential, commercial and industrial customers (5.6%, 5.7%, and 4.8%, respectively) and higher energy related rates that became effective April 1, 2004, which were the result of NPC’s General and Deferred Energy Rate Cases (refer to Regulatory Proceedings in the 2004 10-K). Based on NPC’s projected customer forecast, the number of customers in all sectors is expected to increase in the upcoming months.

The decrease in Electric Operating Revenues – Other for the three months ended March 31, 2005, compared to the same period in 2004, was primarily due to a decrease in the sales volumes for wholesale electric power to other utilities. See the 2004 10-K, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation – Energy Supply for a discussion of NPC’s purchase power procurement strategies.

Purchased Power


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Purchased Power	$	141,428	$	127,531		10.9	%
Purchased Power in thousands of MWhs		2,240		2,361		-5.1	%
Average cost per MWh of Purchased Power	$	63.14	$	54.02		16.9	%

NPC’s purchased power costs were higher for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to higher prices of purchased power. NPC has two contracts with cost per MWh, which are calculated using gas indexes. Additionally, NPC has two gas tolling agreements, entered into in the second quarter 2004, with the gas provided by NPC. Therefore, the increase in natural gas prices in the first quarter of 2005 compared to the same period in 2004 increased the cost of purchased power. The decrease in volume was due to NPC satisfying more of its native load requirements through generation rather than purchased power.

Fuel For Power Generation


	Three Months Ended March 31,
					Change
					from Prior
	2005		2004		Year %
Fuel for Power Generation	$	55,640	$	49,355		12.7	%

Thousands of MWhs generated		1,886		1,788		5.5	%
Average cost per MWh of Generated Power	$	29.50	$	27.60		6.9	%

Fuel for power generation costs increased in the three months ended March 2005 compared to the same period in 2004 due to higher volumes and higher costs to generate electricity. The increase in the volume of generation was primarily due to NPC satisfying more of its native load requirements through generation rather than purchased power. The increase in the average unit fuel cost per megawatt-hour was due to higher natural gas prices.

Deferred Energy Costs — Net


	Three Months Ended March 31,
					Change
					from Prior
	2005		2004		Year %
Deferred energy costs disallowed	$	—	$	1,586		N/A
Deferred energy costs — net		35,823		43,318		-5.5	%

Total	$	35,823	$	44,904

Deferred energy costs disallowed for the three months ended March 31, 2004, consisted of the write-off of $1.6 million of deferred energy costs incurred during the twelve months ended September 30, 2003, that were disallowed by the PUCN in NPC’s 2003 deferred energy rate case in March 2004. See, Regulatory, NPC’s 2003 Deferred Energy Rate Case in the 2004 10-K.

Deferral of energy costs — net decreased for the three months ended March 31, 2005 compared to the same period in 2004 as a result of actual fuel and purchased power costs exceeding fuel and purchased power costs recovered through rates during the three months ended March 31, 2005. During periods when actual fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as a reduction in costs.

See “Critical Accounting Policies” and Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in the 2004 10-K for more information regarding deferred energy accounting.

Allowance for Funds Used During Construction (AFUDC)


	Three Months Ended March 31,
					Change
					from Prior
	2005		2004		Year %
Allowance for other funds used during construction	$	3,490	$	657		N/A

Allowance for borrowed funds used during construction	$	4,313	$	930		N/A

	$	7,803	$	1,587		N/A

AFUDC is higher for the three months ended March 31, 2005 compared to the same period in 2004 due to an increase in Construction Work in Progress (CWIP). The increase is primarily due to the purchase of the partially completed Chuck Lenzie Generation Plant in October 2004 and associated construction costs.

Other (Income) and Expenses


	Three Months Ended March 31,
							Change
							from Prior
	2005			2004			Year %
Other operating expense	$	51,099		$	39,722			28.6	%
Maintenance expense	$	16,955		$	19,956			-15.0	%
Depreciation and amortization	$	30,402		$	28,739			5.8	%
Income tax benefits	$	(6,794	)	$	(11,453	)		-40.7	%
Interest charges on long-term debt	$	41,529		$	37,151			11.8	%
Interest charges-other	$	4,332		$	4,587			-5.6	%
Interest accrued on deferred energy	$	(4,525	)	$	(5,395	)		-16.1	%
Disallowed merger costs		—		$	3,961			N/A
Other income	$	(6,913	)	$	(5,740	)		20.4	%
Other expense	$	1,576		$	1,441			9.4	%
Income taxes — other income and expense	$	3,102		$	1,988			56.0	%

Other operating expense increased for the three-month period ended March 31, 2005 compared to the same period in 2004 primarily due to increased advisory fees, amortization of regulatory assets and severance costs associated with the reorganization of NPC, SPPC and SPR.

Maintenance expense decreased for the three-month period ended March 31, 2005 compared to the same period in 2004 due to outages scheduled at Clark Station in the first quarter of 2004.

Depreciation and amortization expenses were higher in the first quarter of 2005 compared to the same period in 2004 primarily as a result of increases to plant-in-service.

NPC’s Income tax benefits for the three months ended March 31, 2005, decreased compared to the same period in 2004, as a result of a decrease in the pretax net loss.

Interest charges on Long-Term Debt increased for the three months ended March 31, 2005 compared to the same period in 2004 due to higher debt balances during the three months ended March 31, 2005. See Note 7, Long-Term Debt of the Notes to Consolidated Financial Statements in the 2004 10-K for additional information regarding long-term debt.

Interest charges-other for the three months ended March 31, 2005 was comparable to the same period 2004.

Interest accrued on deferred energy costs decreased for the three months ended March 31, 2005 compared to the same period 2004 primarily due to lower deferred fuel and purchased power balances during 2005.

NPC did not incur any disallowed merger costs for the three months ended March 31, 2005, nor does NPC expect to incur any disallowed merger costs in the remainder of 2005. Disallowed merger costs for the three months ended March 31, 2004 were a result of the PUCN decision in NPC’s 2003 General Rate Case. Disallowed merger costs expense 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 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” – in the 2004 10-K.

NPC’s Other income increased for the three months ended March 31, 2005, compared to the same period in 2004 due to increased interest income from temporary investments and continued gains from the disposition of non-utility property.

NPC’s Other expense for the three months ended March 31, 2005 was comparable to the same period in 2004.

Income Taxes-Other Income and Expense increased for the three months ended March 31, 2005 compared to the same quarter in 2004 due to an increase in other non-operating income.

ANALYSIS OF CASH FLOWS

NPC’s cash flows were higher during the three months ended March 31, 2005, compared to the same period in 2004 resulting primarily from an increase in cash flows from operating and financing offset by an increase in cash used for investing activities. The increase in cash from operating activities were higher in the 2005 period due to energy related rate increases that became effective in the second quarter of 2004, which were the result of NPC’s General and Deferred Energy Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash from operating activities for the first quarter of 2005 compared to the same period in 2004 was a result of the $24 million escrow payment made by the Utilities to Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of revolving credit facilities and improved positions in hedging activity due to increasing energy prices. In addition, cash used in investing activities increased mainly due to an increase in utility construction of the Lenzie project under construction in 2005, which is primarily being funded through internally generated funds. Cash used in financing activities primarily increased due to dividend payments to SPR of $19.9 million.

LIQUIDITY AND CAPITAL RESOURCES

NPC had cash and cash equivalents of approximately $188 million at March 31, 2005.

NPC anticipates it will be able to meet fuel and purchased power costs through internally generated funds, including the recovery of deferred energy and if necessary the use of its $350 million revolving credit facility. As discussed in Construction Expenditures and Financing and Contractual Obligations in the 2004 10-K, NPC anticipates capital requirements for construction costs in 2005 will be approximately $629.8 million, which NPC expects to finance with internally generated funds and if necessary the use of its $350 million revolving credit facility. As of May 9, 2005, NPC has no outstanding borrowings under this facility.

During the three months ended March 31, 2005, there were no material changes to contractual obligations as set forth in NPC’s 2004 10-K.

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 March 31, 2005, $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.

NPC does not anticipate that the First Mortgage Indenture dividend restriction as amended, 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 March 31, 2005, $1.3 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 March 31, 2005 (which do not include additions to plant associated with the acquisition of the Lenzie Generating Station), NPC had the capacity to issue approximately $299 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, Series I, and Series L 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.

Limitations on Indebtedness

Certain of NPC’s financing agreements contain restrictions on NPC’s ability to issue additional indebtedness. The restrictions on issuing additional indebtedness in NPC’s various financing agreements are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Nevada Power Company – Liquidity and Capital Resources.” Under the terms of the limitations on issuing additional indebtedness, which remain unchanged from their description in the 2004 10-K, NPC would have been able to issue additional indebtedness. In addition, the terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014, contain restrictions on SPR’s, NPC’s and SPPC’s ability to issue additional indebtedness. As of March 31, 2005, NPC and SPPC are restricted to issuing no more than approximately $550 million of additional indebtedness on a consolidated basis, assuming an interest rate of 8 5/8% based upon SPR’s most recent debt issuance, unless the indebtedness being issued is specifically permitted under the terms of SPR’s 8 5/8% Senior Notes due 2014. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Resources – Liquidity and Capital Resources (SPR Consolidated) – Limitations on Indebtedness” for a description of the applicable restrictions.

Financial Covenants

NPC’s 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. As of March 31, 2005, NPC was in compliance with both of the financial maintenance covenants.

Cross Default Provisions

NPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by NPC upon an event of default by SPR or SPPC under any of their respective financing agreements. Certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC 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 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 in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Nevada Power Company – Liquidity and Capital Resources,” and remain unchanged from their description in the 2004 10-K.

Judgment Related Defaults

Certain of NPC’s financing agreements contain judgment default provisions that provide for an event of default if a final, unstayed judgment is rendered against NPC and remains undischarged after 60 days. The judgment default provisions in NPC’s various financing agreements and the consequences of a judgment default for NPC are summarized in the 2004 10-K in

“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Nevada Power Company – Liquidity and Capital Resources.” There have been no changes to NPC’s judgment default provisions as described in the 2004 10-K.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended March 31, 2005, SPPC recognized net income of approximately $12.1 million compared to $7.7 million for the same period in 2004. During the three months ended March 31, 2005, SPPC declared and paid $975 thousand in dividends. On May 3, 2005, SPPC declared an additional $975 thousand 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.

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 components of gross margin were (dollars in thousands):


	Three Months Ended March 31,
							Change from
	2005			2004			Prior Year %
Operating Revenues:
Electric	$	227,010		$	201,841			12.5	%
Gas		67,538			59,476			13.6	%

	$	294,548		$	261,317			12.7	%


Energy Costs:
Purchased Power	$	78,724		$	65,960			19.4	%
Fuel for power generation		54,362			53,802			1.0	%
Deferral of energy costs-electric-net		4,293			4,571			-6.1	%
Gas purchased for resale		53,480			47,917			11.6	%
Deferral of energy costs-gas-net		(328	)		(1,407	)		-76.7	%

		190,531			170,843			11.5	%


Energy Costs by Segment:
Electric	$	137,379		$	124,333			10.5	%
Gas		53,152			46,510			14.3	%

	$	190,531		$	170,843			11.5	%


Gross Margin by Segment:
Electric	$	89,631		$	77,508			15.6	%
Gas		14,386			12,966			11.0	%

	$	104,017		$	90,474			15.0	%

The causes of 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 Ended March 31,
					Change from
	2005		2004		Prior year %
Electric Operating Revenues:
Residential	$	73,572	$	62,960		16.9	%
Commercial		72,543		64,873		11.8	%
Industrial		73,335		66,556		10.2	%

Retail		219,450		194,389		12.9	%
Other¹		7,560		7,452		1.4	%

Total Revenues	$	227,010	$	201,841		12.5	%


Retail sales in thousands of MWh		2,296		2,233		2.8	%
Average retail revenue per MWh	$	95.58	$	87.05		9.8	%

Primarily wholesale, as discussed below.

SPPC’s retail revenues increased for the three months ended March 31, 2005 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, and an increase in California customer energy rates, effective December 1, 2004 (refer to “Regulatory Proceedings” in the 2004 10-K). Also contributing to the increase was the growth in residential and commercial customers (3.6% and 3.2%, respectively).

The increase in Electric Operating Revenues-Other for the three month period ended March 31, 2005 compared to the same period in 2004 was primarily due to an increase in purchased power sales.

Gas Operating Revenues


	Three Months Ended March 31,
					Change from
	2005		2004		Prior year %
Gas Operating Revenues:
Residential	$	37,519	$	31,386		19.5	%
Commercial		18,619		15,632		19.1	%
Industrial		5,723		4,046		41.4	%

Retail revenue		61,861		51,064		21.1	%
Wholesale revenue		5,020		7,612		-34.1	%
Miscellaneous		657		800		-17.9	%
Total Revenues	$	67,538	$	59,476		13.6	%


Retail sales in thousands of decatherms		6,399		5,561		15.1	%

Average retail revenues per decatherm	$	9.67	$	9.18		5.3	%

Retail gas revenues increased for the three months ended March 31, 2005 primarily due to colder temperatures in the first quarter 2005 as compared to the same period of 2004. Also contributing to this increase was an increase in energy related rates that became effective November 1, 2004. This increase in the retail 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 2004 10-K). Also influencing this increase is the growth of retail customers of 4.4%.

Wholesale gas revenues for the three months ending March 31, 2005 decreased from the same period in 2004 due to the increase in retail usage discussed above which decreased the availability of gas for wholesale sales.

Purchased Power


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Purchased Power:	$	78,724	$	65,960		19.4	%

Purchased Power in thousands of MWhs		1,400		1,204		16.3	%
Average cost per MWh of Purchased Power	$	56.23	$	54.78		2.7	%

Purchased power costs increased for the three months ended March 31, 2005 as compared to the same period in 2004 primarily due to higher volumes and higher prices of purchased power. The increase in volume was the result of SPPC relying more on purchased power to satisfy its native load requirements. The average unit cost per megawatt-hour was higher in 2005 compared to 2004 due to a lower availability of hydroelectric power in the Pacific Northwest.

Fuel For Power Generation


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Fuel for Power Generation	$	54,362	$	53,802		1.0	%

Thousands of MWh generated		1,071		1,187		-9.8	%
Average fuel cost per MWh of Generated Power	$	50.76	$	45.33		12.0	%

Fuel for power generation costs increased for the three months ended March 31, 2005 as compared to the same period in 2004 primarily due to higher natural gas and coal prices. The decrease in the volume of generation was due to SPPC relying more on purchased power to satisfy its native load requirements.

Gas Purchased for Resale


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Gas Purchased for Resale	$	53,480	$	47,917		11.6	%

Gas Purchased for Resale (in thousands of decatherms)		7,359		7,229		1.8	%

Average cost per decatherm	$	7.27	$	6.63		9.6	%

The cost of gas purchased for resale increased for the three months ended March 31, 2005 as compared to the same period in 2004 primarily due to increases in natural gas prices and the increase in customer usage which was the result of colder winter weather.

Deferred Energy Costs


	Three Months Ended March 31,
							Change from
	2005			2004			Prior Year %
Deferred energy costs – electric – net	$	4,293		$	4,571			-6.1	%
Deferred energy costs — gas — net		(328	)		(1,407	)		-76.7	%

Total	$	3,965		$	3,164

The decrease in deferred energy costs — electric — net for the three months ended March 31, 2005, compared to the same period in 2004, was due to actual fuel and purchased power costs exceeding recovery of fuel and purchased power costs through current rates, as well as a decrease in the amortization of prior deferred energy costs. During periods when actual fuel and purchase power costs exceed amounts recovered through rates, the excess is shown as a reduction in costs.

SPPC’s Deferred energy costs — gas — net decreased for the three months ended March 31, 2005, primarily as a result of lower amortization of prior deferred energy costs in 2005 as compared with 2004 due to lower rates. Partially offsetting this decrease was an increase in the recovery of actual natural gas costs through rates in 2005 compared to the recovery of costs through rates in 2004.

Allowance for Funds Used During Construction (AFUDC)


	Three Months Ended March 31,
					Change from
	2005		2004		Prior Year %
Allowance for other funds used during construction	$	319	$	716		-55.4	%

Allowance for borrowed funds used during construction	$	290	$	1,243		-76.7	%

	$	609	$	1,959		-68.9	%

AFUDC is lower for the three months ended March 31, 2005 compared to the same period in 2004 due to a decrease in Construction Work-In-Progress (CWIP) as a result of the completion of the Falcon to Gonder transmission line, which was placed in service in May 2004.

Other (Income) and Expense


	Three Months Ended March 31,
							Change
							from Prior
	2005			2004			Year %
Other operating expense	$	34,769		$	30,811			12.8	%
Maintenance expense	$	5,991		$	4,932			21.5	%
Depreciation and amortization	$	22,387		$	21,198			5.6	%
Income tax expense	$	6,603		$	876			N/A
Interest charges on long-term debt	$	17,307		$	18,868			-8.3	%
Interest charges-other	$	1,146		$	2,157			-46.9	%
Interest accrued on deferred energy	$	(1,583	)	$	(1,154	)		37.2	%
Disallowed merger costs		—		$	1,929			N/A
Other income	$	(971	)	$	(860	)		12.9	%
Other expense	$	1,640		$	1,313			24.9	%
Income taxes (benefit) – other income and expense	$	452		$	(323	)		N/A

Other operating expense increased for the three-month period ended March 31, 2005 compared to the same period in 2004 primarily due to increased legal fees, amortization of regulatory assets and severance costs associated with the reorganization of SPPC, NPC and SPR.

Maintenance cost increased by several items, none of which were individually significant.

Depreciation and amortization expenses were higher in the first quarter of 2005 compared to the same period in 2004 primarily as a result of increases to plant-in-service. The major contributor to this increase was the addition of the Falcon to Gonder transmission line, which was placed in service May 2004.

SPPC’s Income tax expense for the three months ended March 31, 2005, increased compared to the same period in 2004, as a result of an increase in pretax net income.

SPPC’s interest charges-Long-term debt for the three months ended March 31, 2005 decreased from the same period in 2004 due to lower rates of interest on new and existing debt. See Note 7, Long-Term Debt of the Notes to Financial Statements in the 2004 10-K for additional information regarding long-term debt.

SPPC’s interest charges-other for the three months ended March 31, 2005 decreased compared to the same period in 2004 due primarily to the absence of charges related to the accounts receivable facility and short-term debt. See Note 6, Short-Term Borrowings, of the Notes to Financial Statements in the 2004 10-K for additional information.

Interest accrued on deferred energy costs increased for the three months ended March 31, 2005 compared to the same period in 2004 due to higher deferred fuel and purchased power balances and rates during 2005.

SPPC did not incur any disallowed merger costs for the three months ended March 31, 2005, nor does SPPC expect to incur any disallowed merger costs in 2005. Disallowed merger costs for the three months ended March 31, 2004 was a result of the PUCN decision in SPPC’s 2004 General Rate Case. Disallowed merger costs expense includes the 2004 write-off of costs that resulted from the July 28, 1999 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” – in the 2004 10-K.

SPPC’s Other expense increased for the three months ended March 31, 2005 compared to the same period in 2004, due to various charges, all of which were not individually significant.

Income taxes – other income and expense recorded income tax expense for the three months ended March 31, 2005 compared to an income tax benefit recognized during the same period in 2004. The change resulted primarily from pretax net income – other income recognized for the quarter ended March 31, 2005 compared to a pretax net loss – other income recognized for the same period in 2004.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows during the three months ended March 31, 2005 compared to the same period in 2004 increased primarily as a result of an increase in cash flows from operating and financing activities partially offset by an increase in cash used in investing activities. Cash flows from operating activities were higher in the 2005 period due to energy related rate increases that became effective the second quarter of 2004, which was the result of SPPC’s General and Deferred Energy Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash from operating activities for the first quarter of 2005 compared to the same period in 2004 was a result of the $11 million escrow payment made by the Utilities to Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of revolving credit facilities and changes in receivables for tax sharing agreements. Cash flows from financing activities increased in 2005, when compared to 2004, due to the repayment of $25 million in short-term borrowings in March 2004. Cash flows used in investing activities increased primarily as a result of an increase in construction activity related to growth.

LIQUIDITY AND CAPITAL RESOURCES

SPPC had cash and cash equivalents of approximately $90 million at March 31, 2005.

SPPC anticipates it will be able to meet fuel and purchased power costs through internally generated funds, including the recovery of deferred energy. As discussed in Construction Expenditures and Financing and Contractual Obligations in the 2004 10-K, SPPC anticipates capital requirements for construction costs during 2005 totaling approximately $176.6 million, which SPPC expects to finance with internally generated funds and, if necessary, the use of its revolving credit facility. As of May 9, 2005, SPPC has not drawn on its revolving credit facility.

During the three months ended March 31, 2005, there were no material changes to contractual obligations as set forth in SPPC’s 2004 10-K.

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 March 31, 2005, $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 March 31, 2005, there were $420 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 March 31, 2005, SPPC had the capacity to issue approximately $350 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.

Limitations on Indebtedness

Certain of SPPC’s financing agreements contain restrictions on SPPC’s ability to issue additional indebtedness. The restrictions on issuing additional indebtedness in SPPC’s various financing agreements are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Power Company – Liquidity and Capital Resources.” Under the terms of the limitations on issuing additional indebtedness, which remain unchanged from their description in the 2004 10-K, SPPC would have been able to issue additional indebtedness. In addition, the terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014, contain restrictions on SPR’s, NPC’s and SPPC’s ability to issue additional indebtedness. As of March 31, 2005, NPC and SPPC are restricted to issuing no more than approximately $550 million of additional indebtedness on a consolidated basis, assuming an interest rate of
8 5/8% based upon SPR’s most recent debt issuance, unless the indebtedness being issued is specifically permitted under the terms of SPR’s
8 5/8% Senior Notes due 2014. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Resources – Liquidity and Capital Resources (SPR Consolidated) – Limitations on Indebtedness” for a description of the applicable restrictions.

Financial Covenants

SPPC’s 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. As of March 31, 2005, SPPC was in compliance with both of the financial maintenance covenants.

Cross Default Provisions

SPPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by SPPC upon an event of default by SPR or NPC under any of their respective financing agreements. Certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC 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 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 in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Power Company – Liquidity and Capital Resources,” and remain unchanged from their description in the 2004 10-K.

Judgment Related Defaults

Certain of SPPC’s financing agreements contain judgment default provisions that provide for an event of default if a final, unstayed judgment is rendered against SPPC and remains undischarged after 60 days. The judgment default provisions in SPPC’s various financing agreements and the consequences of a judgment default for SPPC are summarized in the 2004 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Power Company – Liquidity and Capital Resources.” There have been no changes to SPPC’s judgment default provisions as described in the 2004 10-K.

REGULATORY PROCEEDINGS (UTILITIES)

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for, generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit Integrated Resource Plans (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 also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies. 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 2004 Deferred Energy Case

On November 15, 2004, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between October 1, 2003 and September 30, 2004, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $116 million, with a carrying charge. The application requested that the 2004 Deferred Energy Accounting Adjustment (DEAA) recovery begin with the expiration of the 2002 DEAA recovery, which is expected to occur in May 2006 and for the 2004 DEAA recovery period to be 22 months.

The application also requested an increase to the going-forward base tariff energy rate (BTER).

Sierra Pacific Power Company 2005 Deferred Energy Case

On January 14, 2005, SPPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between December 1, 2003 and November 30, 2004, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $28 million, with a carrying charge. The application requested that the 2005 Deferred Energy Accounting Adjustment (DEAA) recovery begin on June 1, 2005 together with the commencement of recovery of the 2004 DEAA balance both of which are coincident with the expiration of the 2002 and 2003 DEAA recovery. SPPC has requested a 24-month recovery period for the 2005 DEAA balance.

The application also requested an increase to the going-forward base tariff energy rate (BTER).

On April 6, 2005, the PUCN Staff and the BCP filed written direct testimony in this case. The testimony recommended full recovery of the deferred balance after a $575 thousand reduction to reflect an accounting adjustment mutually agreed to by the parties. The PUCN Staff recommended adoption of the higher BTER rate that SPPC filed on March 30, 2005 while the BCP opposed the implementation of the higher BTER.

The PUCN held a hearing on April 18, 2005 and has indicated it will issue a ruling on May 17, 2005.

For further detail of deferred energy cases see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2004 10-K.

Nevada Power Company/Sierra Pacific Power Company Quality of Service Investigation

In compliance with the order issued in NPC’s 2003 General Rate case, NPC and SPPC jointly filed with the PUCN, on July 1, 2004, their recommended quality of service and customer service measurements. In the filing, the Utilities outlined their proposed methodologies for measuring the quality of service and customer service measurements, pre and post merger. More specifically the companies identified the quality of service and customer service measurements to be used in a future rate case, proposed methodology for comparing pre-merger and post-merger performance, and proposed consequences and rewards for under- or over- performance in a future test year. The PUCN has noticed the filing and has set a procedural schedule. On March 2, 2005, the Intervener’s in the case, the staff of the PUCN and the BCP, filed testimony regarding their proposed methodologies for measuring quality of service and customer service measurements. The Utilities filed rebuttal testimony on April 18, 2005. A hearing has been scheduled to commence on May 16, 2005.

FERC Matters

Sierra Pacific Power Company 2004 Transmission Rate Case

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. The participants in the proceeding have filed a Settlement Agreement with the FERC which has been certified by the Settlement judge. FERC is expected to issue an order approving settlement in the second quarter of 2005.

RECENT PRONOUNCEMENTS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2005, SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt and preferred trust securities. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).


						Expected Maturity Date
																						Fair
	2005			2006			2007			2008			2009			Thereafter			Total			Value
Long-term Debt
SPR
Fixed Rate	$	—		$	—		$	240,218		$	—		$	—		$	635,000		$	875,218		$	1,310,901
Average Interest Rate		—			—			7.93	%		—			—			7.98	%		7.96	%

NPC
Fixed Rate	$	11		$	15		$	17		$	13		$	250,000		$	1,863,548		$	2,113,604		$	2,212,822
Average Interest Rate		8.17	%		8.17	%		8.17	%		8.17	%		10.88	%		7.32	%		7.74	%
Variable Rate													$	15,000		$	100,000		$	115,000		$	115,000
Average Interest Rate														1.74	%		1.74	%		1.74	%

SPPC
Fixed Rate	$	1,693		$	52,400		$	2,400		$	322,400		$	600		$	617,250		$	996,743		$	1,023,987
Average Interest Rate		6.10	%		6.71	%		6.10	%		6.10	%		6.10	%		6.52	%		7.00	%

Total Debt	$	1,704		$	52,415		$	242,635		$	322,413		$	265,600		$	3,215,798		$	4,100,565		$	4,662,710

Commodity Price Risk

See the 2004 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, 2004.

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 $53 million as of March 31, 2005, which increased significantly from December 31, 2004 due to an increase in trading transactions to meet the demand of the summer months and a general increase in power market prices of approximately $5 — $7 per MWh. 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 March 31, 2005, the registrants’ disclosure controls and procedures were adequate and effective.

(b)

Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the first quarter of 2005 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

On October 10, 2004, the U.S. District Court for the Southern District of New York rendered a decision vacating an earlier judgment by the Bankruptcy Court (also for the Southern District of New York) against the Utilities in favor of Enron Power Marketing, Inc. (Enron), and remanded the case back to the Bankruptcy Court for fact-finding. A description of the legal proceedings leading up to the District Court’s order to vacate follows, along with a discussion of all pending matters related to the Enron litigation.

Bankruptcy Court Judgment

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 approximately $282 thousand 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 and 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 lowered 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 triggered the Utilities’ rights to seek recovery of such amounts through the Utilities’ deferred energy rate cases.

District Court for the Southern District of New York. 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.

Appeal of Bankruptcy Court Judgment to U.S. District Court

	•	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 Utilities filed a motion seeking clarification of the U.S. District Court rulings with respect to the Utilities’ affirmative defenses and counterclaim 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. This motion did not relate to Enron’s claims against the Utilities, which the U.S. District Court addressed in its October 10, 2004 decision described above. On December 23, 2004, the U.S. District Court ruled on this motion, affirming the dismissal of the Utilities’ affirmative defenses and counterclaims on the grounds that they were barred under the filed rate doctrine. However, the U.S. District Court ruled in favor of the Utilities on the calculation of pre-judgment interest.

FERC Early Termination Case

payment profits; and (c) whether Enron should be otherwise denied the authority to collect such payments because to do so would be contrary to the public interest.

Bankruptcy Court Injunction and Order Setting Trial

After the U.S. District Court issued its October 10, 2004 ruling, Enron renewed its motion with the Bankruptcy Court seeking to enjoin the Utilities from proceeding in the FERC Early Termination Case. On December 3, 2004 the Bankruptcy Court enjoined the Utilities from further prosecution of the scheduled hearing in the FERC proceeding. The Utilities have appealed this decision and are seeking a stay of the trial in Bankruptcy Court pending the outcome of the FERC Early Termination Case. The trial is currently set for July 11, 2005. The Utilities are unable to predict the outcome of these proceedings at this time.

FERC Revocation Show Cause Proceeding

FERC Gaming and Partnership Show Cause Proceeding

On June 25, 2003, FERC issued orders in two separate cases involving Enron and potential gaming of power markets. The first was referred to as the “Gaming Show Cause Proceeding” and the second as the “Partnership Show Cause Proceeding”. The proceedings focused on Enron’s illicit trading activity in California with a variety of counterparties. On July 21, 2004, FERC consolidated the two proceedings and expanded the scope of its inquiry. FERC announced that it was revisiting its decision not to revoke Enron’s market-based rate authority and that “Enron potentially could be required to disgorge profits for all of its wholesale power sales in the Western Interconnect for the period January 16, 1997 to June 15, 2003.” Enron has sought rehearing of this order, challenging the expanded scope of the proceeding. The Utilities have joined a coalition of other Western Parties and on August 4, 2004, sought clarification that remedies other than disgorgement might be available. On March 11, 2005, the FERC issued an order clarifying issues to be covered in the administrative trial scheduled to begin June 13, 2005. In that order, the FERC stated that Enron’s profits under the terminated power contracts fell within the scope of that proceeding. The trial is currently set for September 7, 2005. The Utilities are unable to predict the outcome of the trial at this time.

FERC 206 complaints

The Utilities are contesting the amounts paid for power actually delivered by these suppliers 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 Utilities 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 was held on December 8, 2004 and a decision is pending. The Utilities are unable to predict the outcome of this appeal at this time.

Reliant Antitrust Litigation

Nevada Power Company

Morgan Stanley Proceedings

NPC filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada (District Court) 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 District Court granted the stay for another 90 days. At the February 28, 2005 status conference, the Judge lifted the stay and ordered the case to go forward. The parties will meet to set the discovery and trial schedule. On February 28, 2005, NPC filed a motion for summary judgment. MSCG filed its own summary judgment motion on March 17, 2005. A hearing on the motions has been set for June 6, 2005. At this time, NPC is unable to predict the outcome or timing of the District Court complaint.

El Paso Merchant Energy

in this matter.

Nevada Power Company 2001 Deferred Energy Case

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

On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. NPC and the Bureau of Consumer Protection (BCP) both sought individual review of the PUCN 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. As a result of that mandatory process, NPC filed a motion with the Nevada Supreme Court seeking remand of the 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.

A briefing schedule on the underlying appeal has since been established. A decision is not expected for six to twelve months. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Environmental Matters

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.

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 maintenance records, operating logs, recorded oil/coal data and other information pertaining to the sources identified in the Title V permit were requested. NPC has provided information in connection with this and subsequent requests. In September and October 2004, NPC met with the Nevada Division of Environmental Protection (NDEP) to review the outcome of NDEP’s inspection. NDEP informed NPC that it may not be in compliance with certain aspects of its Title V permit and on December 2, 2004 issued Notices of Alleged Violation (NOAVs). NPC is continuing to provide information to NDEP as requested. Because no penalty has been specified by NDEP and discussions are continuing, management cannot reasonably estimate the amount of any potential monetary penalties that may ultimately be assessed in connection with the alleged violations.

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 $43 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 2004. Answering and Reply briefs were filed in November and December and oral argument was presented on April 29, 2005. SPPC expects the Court to rule within the second or third quarter of 2005, but cannot predict the outcome of the case.

Sierra Pacific Resources and Nevada Power Company

Lawsuit Against Natural Gas Providers

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

The Second Amended Complaint names three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company (El Paso); (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company (SoCal), and San Diego Gas and Electric (SDG&E) (collectively Sempra). New motions to dismiss were filed by all of the defendants and a hearing was held on November 29, 2004. The District Court granted the defendants’ motions to dismiss. The case has been appealed to the Ninth Circuit Court of Appeals. At this time, management cannot predict the timing or outcome of a decision on this matter.

Investment Banker Complaint

On November 19, 2004, SPR and NPC filed suit in United States District Court, District of Nevada, against Citigroup, Inc., Solomon Smith Barney, Inc., J.P. Morgan Chase Bank and numerous other investment banks and financial institutions asserting claims for damages arising out of the defendants’ conduct in acting in concert with Enron to falsely portray Enron’s financial condition and induce the reliance of business counterparties, including NPC, upon the statements and representations of Enron regarding its financial health in the 1990s and early 2000 time period. The suit alleges, among other things, that the defendants aided and abetted Enron’s fraud through financial transactions with so-called Special Purpose Entities, which were designed to conceal Enron liabilities or artificially inflate revenues and reported financial condition. The complaint seeks damages in excess of $500 million.

Effective January 10, 2005, the suit was transferred to MDL-1446,In re Enron Corp. Securities, Derivative and Erisa Litigation, pending in the U.S.D.C. in Houston Texas before Judge Melinda Harmon. At this time the Utilities are unable to predict the outcome or the timing of future proceedings related to the complaint.

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

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

None

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS

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

Nevada Power Company


Exhibit 10.1		Collective Bargaining Agreement dated as of February 1, 2005, effective through February 1, 2008, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396.

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.

SIGNATURES

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


		Sierra Pacific Resources

		(Registrant)

Date: May 9, 2005	By:	/s/ Michael W. Yackira

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

Date: May 9, 2005	By:	/s/ John E. Brown

		John E. Brown
		Controller
		(Principal Accounting Officer)

		Nevada Power Company

		(Registrant)

Date: May 9, 2005	By:	/s/ Michael W. Yackira

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

Date: May 9, 2005	By:	s/ John E. Brown

		John E. Brown
		Controller
		(Principal Accounting Officer)

		Sierra Pacific Power Company

		(Registrant)

Date: May 9, 2005	By:	/s/ Michael W. Yackira

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

Date: May 9, 2005	By:	s/ John E. Brown

		John E. Brown
		Controller
		(Principal Accounting Officer)

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

Sierra Pacific Power 10-Q2005 Q1 Quarterly report

Content analysis