Sierra Pacific Power 10Q 2005 Q3 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 September 30, 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 by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 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 November 2, 2005
Common Stock, $1.00 par value		183,422,627 Shares
of Sierra Pacific Resources

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

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

SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2005

CONTENTS


PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements

Sierra Pacific Resources -
Consolidated Balance Sheets – September 30, 2005 and December 31, 2004			3

Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2005 and 2004			4

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2005 and 2004			5

Consolidated Statements of Capitalization – September 30, 2005 and December 31, 2004			6

Nevada Power Company -
Consolidated Balance Sheets – September 30, 2005 and December 31, 2004			8

Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2005 and 2004			9

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2005 and 2004			10

Sierra Pacific Power Company -
Consolidated Balance Sheets – September 30, 2005 and December 31, 2004			11

Consolidated Statements of Operations – Three Months and Nine Months Ended September 30, 2005 and 2004			12

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2005 and 2004			13

Condensed Notes to Consolidated Financial Statements			14

ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations			35
Sierra Pacific Resources			41
Nevada Power Company			46
Sierra Pacific Power Company			53

ITEM 3.Quantitative and Qualitative Disclosures about Market Risk			67

ITEM 4.Controls and Procedures			68

PART II — OTHER INFORMATION
ITEM 1.Legal Proceedings			69

ITEM 4.Submission of Matters to a Vote of Security Holders			76

ITEM 5.Other Information			76

ITEM 6.Exhibits			76

Signature Page and Certifications			78
EX-4.1 OFFICER'S CERTIFICATE DATED AUGUST 12, 2005
EX-4.2 FORM OF SIERRA PACIFIC RESOURCES 6 3/4 % SENIOR NOTES
EX-4.3 REGISTRATION RIGHTS AGREEMENT
EX-10.1 SECOND AMENDED AND RESTATED CREDIT AGREEMENT (NEVADA POWER CO.) DATED NOVEMBER 4, 2005
AMENDED AND RESTATED CREDIT AGREEMENT (SIERRA PACIFIC POWER CO.) DATED NOVEMBER 4, 2005
EX-31.1 SECTION 302 CERTIFICATION OF C.E.O.
EX-31.2 SECTION 302 CERTIFICATION OF C.F.O.
EX-32.1 SECTION 906 CERTIFICATION OF C.E.O.
EX-32.2 SECTION 906 CERTIFICATION OF C.F.O.

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)
(Unaudited)


	September 30,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,792,578	$	6,604,449
Less accumulated provision for depreciation		2,162,078		2,083,434

		4,630,500		4,521,015
Construction work-in-progress		681,097		405,911

		5,311,597		4,926,926

Investments and other property, net		62,696		64,596


Current Assets:
Cash and cash equivalents		173,019		266,328
Restricted cash and investments (Note 1)		65,488		88,452
Accounts receivable less allowance for uncollectible accounts: 2005-$40,584; 2004-$36,197		409,394		320,676

Deferred energy costs — electric (Note 1)		187,868		148,008
Deferred energy costs — gas (Note 1)		4,086		3,106
Materials, supplies and fuel, at average cost		81,990		76,193
Risk management assets (Note 7)		212,942		14,585
Deposits and prepayments for energy		35,601		54,767
Other		24,405		37,494

		1,194,793		1,009,609

Deferred Charges and Other Assets:
Goodwill (Note 11)		22,877		22,877
Deferred energy costs — electric (Note 1)		525,663		526,159
Deferred energy costs — gas (Note 1)		2,899		2,491
Regulatory tax asset		275,585		279,766
Other regulatory assets		504,942		487,762
Risk management regulatory assets — net (Note 7)		—		6,673
Unamortized debt issuance expense		62,513		67,204
Other		134,263		114,297

		1,528,742		1,507,229

Assets of Discontinued Operations		19,938		20,107

TOTAL ASSETS	$	8,117,766	$	7,528,467

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	1,807,408	$	1,498,616
Preferred stock		50,000		50,000
Long-term debt		3,734,822		4,081,281

		5,592,230		5,629,897

Current Liabilities:
Short-term borrowings		240,000		—
Current maturities of long-term debt		38,804		8,491
Accounts payable		236,761		179,559
Accrued interest		82,199		69,246
Dividends declared		1,043		1,046
Accrued salaries and benefits		30,032		28,547
Deferred income taxes		16,204		54,501
Risk management liabilities (Note 7)		542		9,902
Accrued taxes		6,402		5,470
Contract termination liabilities (Note 8)		306,119		303,460
Other current liabilities		55,343		38,702

		1,013,449		698,924

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		581,938		512,760
Deferred investment tax credit		39,619		42,064
Regulatory tax liability		39,308		40,575
Customer advances for construction		163,344		142,703
Accrued retirement benefits		72,727		67,907
Risk management regulatory liability — net (Note 7)		204,650		—
Contract termination liabilities (Note 8)		24,498		36,753
Regulatory liabilities		273,274		257,495
Other		102,529		89,189

		1,501,887		1,189,446

Liabilities of Discontinued Operations		10,200		10,200

TOTAL CAPITALIZATION AND LIABILITIES	$	8,117,766	$	7,528,467

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
OPERATING REVENUES:
Electric	$	943,290		$	887,224		$	2,193,017		$	2,067,948
Gas		15,574			16,387			115,248			97,742
Other		262			304			873			3,762

		959,126			903,915			2,309,138			2,169,452

OPERATING EXPENSES:
Operation:
Purchased power		504,823			392,771			1,023,594			849,906
Fuel for power generation		153,721			126,710			371,561			343,598
Gas purchased for resale		12,906			11,322			89,410			73,721
Deferred energy costs disallowed		—			—			—			1,586
Deferral of energy costs — electric — net		(94,313	)		6,227			(40,556	)		93,058
Deferral of energy costs — gas — net		(2,001	)		297			(997	)		266
Impairment of goodwill		—			—			—			11,695
Other		96,850			80,912			271,639			244,163
Maintenance		16,937			16,046			64,040			63,150
Depreciation and amortization		53,862			51,435			159,949			153,501
Taxes:
Income tax expense		42,171			45,193			32,658			17,296
Other than income		11,286			10,734			35,115			34,424

		796,242			741,647			2,006,413			1,886,364

OPERATING INCOME		162,884			162,268			302,725			283,088

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,548			717			14,246			3,282
Interest accrued on deferred energy		7,342			6,777			19,359			19,307
Early debt conversion fees		(54,000	)		—			(54,000	)		—
Disallowed merger costs		—			—			—			(5,890	)
Disallowed plant costs		—			—			—			(47,092	)
Other income		9,452			8,214			28,795			25,258
Other expense		(3,430	)		(3,990	)		(11,732	)		(10,220	)
Income (taxes) / benefits		12,132			(3,406	)		1,200			7,392

		(22,956	)		8,312			(2,132	)		(7,963	)

Total Income Before Interest Charges		139,928			170,580			300,593			275,125

INTEREST CHARGES:
Long-term debt		75,820			74,517			232,826			235,696
Other		8,733			5,437			21,414			36,385
Allowance for borrowed funds used during construction		(6,752	)		(1,123	)		(17,283	)		(4,963	)

		77,801			78,831			236,957			267,118


INCOME FROM CONTINUING OPERATIONS		62,127			91,749			63,636			8,007

DISCONTINUED OPERATIONS:

Loss from discontinued operations (net of income taxes) of $51, $163, $48 and $2,091 respectively)		(134	)		(127	)		(128	)		(3,769	)

NET INCOME		61,993			91,622			63,508			4,238
Preferred stock dividend requirements of subsidiary		975			975			2,925			2,925

EARNINGS APPLICABLE TO COMMON STOCK	$	61,018		$	90,647		$	60,583		$	1,313


Amount per share basic and diluted — (Note 9)
Income from continuing operations — basic	$	0.34		$	0.50		$	0.35		$	0.04
Earnings applicable to common stock — basic	$	0.33		$	0.50		$	0.33		$	0.01
Income from continuing operations — diluted	$	0.34		$	0.50		$	0.35		$	0.04
Earnings applicable to common stock — diluted	$	0.33		$	0.49		$	0.33		$	0.01

Weighted Average Shares of Common Stock Outstanding — basic		183,377,256			183,117,111			183,216,650			183,045,191

Weighted Average Shares of Common Stock Outstanding — diluted		183,752,200			183,336,235			183,607,923			183,235,376

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 nine months ended
	September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	63,508		$	4,238
Non-cash items included in net income:
Depreciation and amortization		159,949			153,501
Deferred taxes and deferred investment tax credit		31,362			7,113
AFUDC and capitalized interest		(31,529	)		(8,245	)
Amortization of deferred energy costs — electric		137,538			206,784
Amortization of deferred energy costs — gas		(486	)		3,126
Deferred energy costs disallowed		—			1,586
Goodwill impairment		—			11,695
Loss on disposal of discontinued operations		—			2,346
Plant costs disallowed		—			47,092
Other non-cash		(33,018	)		(37,109	)
Changes in certain assets and liabilities:
Accounts receivable		(88,718	)		(87,080	)
Deferral of energy costs — electric		(176,901	)		(132,991	)
Deferral of energy costs — gas		(902	)		(2,905	)
Materials, supplies and fuel		(5,797	)		5,716
Other current assets		32,255			(4,369	)
Accounts payable		51,959			17,914
Escrow payment for terminating suppliers		—			(60,867	)
Other current liabilities		32,003			24,192
Change in net assets of discontinued operations		169			131
Other assets		(191,371	)		(10,491	)
Other liabilities		191,178			8,952

Net Cash from Operating Activities		171,199			150,329


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(528,315	)		(264,234	)
AFUDC and other charges to utility plant		31,529			8,245
Customer advances for construction		20,640			13,076
Contributions in aid of construction		15,375			16,973

Net cash used for utility plant		(460,771	)		(225,940	)
Investments in subsidiaries and other property — net		8,105			8,227

Net Cash used by Investing Activities		(452,666	)		(217,713	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (Decrease) in short-term borrowings		240,000			(25,000	)
Change in restricted cash and investments		22,964			27,448
Proceeds from issuance of long-term debt		275,000			565,000
Retirement of long-term debt		(597,236	)		(526,568	)
Issuance of common stock, net of issuance cost		250,366			1,356
Dividends paid		(2,936	)		(2,847	)

Net Cash from Financing Activities		188,158			39,389


Net Decrease in Cash and Cash Equivalents		(93,309	)		(27,995	)
Beginning Balance in Cash and Cash Equivalents		266,328			181,757

Ending Balance in Cash and Cash Equivalents	$	173,019		$	153,762


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	238,944		$	247,070

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
(Unaudited)


	September 30,			December 31,
	2005			2004
Common Shareholder’s Equity:
Common stock, $1.00 par value, authorized 250 million shares; issued and outstanding 2005:183,422,627 shares; issued and outstanding 2004:117,469,000 shares	$	183,423		$	117,469
Other paid-in capital		2,002,851			1,818,453
Retained Earnings Deficit		(377,529	)		(438,112	)
Accumulated Other Comprehensive Income (Loss)		(1,337	)		806

Total Common Shareholder’s Equity		1,807,408			1,498,616

Preferred Stock of Subsidiaries:
Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value
SPPC Class A Series 1; $1.95 dividend		50,000			50,000

Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% NPC Series Z due 2023		35,000			35,000
Debt Secured by First Mortgage Bonds
Revenue Bonds
Nevada Power Company
6.60% NPC Series 1992B due 2019		39,500			39,500
6.70% NPC Series 1992A due 2022		105,000			105,000
7.20% NPC Series 1992C due 2022		78,000			78,000
Sierra Pacific Power Company
6.35% SPPC Series 1992B due 2012		1,000			1,000
6.55% SPPC Series 1987 due 2013		39,500			39,500
6.30% SPPC Series 1987 due 2014		45,000			45,000
6.65% SPPC Series 1987 due 2017		92,500			92,500
6.55% SPPC Series 1990 due 2020		20,000			20,000
6.30% SPPC Series 1992A due 2022		10,250			10,250
5.90% SPPC Series 1993A due 2023		9,800			9,800
5.90% SPPC Series 1993B due 2023		30,000			30,000
6.70% SPPC Series 1992 due 2032		21,200			21,200
Medium Term Notes
Sierra Pacific Power Company
6.62% to 6.83% SPPC Series C due 2006		50,000			50,000
6.95% to 8.61% SPPC Series A due 2022		110,000			110,000
7.10% to 7.14% SPPC Series B due 2023		58,000			58,000

Subtotal		744,750			744,750

General and Refunding Mortgage Securities
Nevada Power Company
10.88% NPC Series E due 2009		162,500			250,000
8.25% NPC Series A due 2011	��	350,000			350,000
6.50% NPC Series I due 2012		130,000			130,000
9.00% NPC Series G due 2019		227,500			350,000
5.875% NPC Series L due 2015		250,000			250,000
Sierra Pacific Power Company
8.00% SPPC Series A due 2008		320,000			320,000
6.25% SPPC Series H due 2012		100,000			100,000

Subtotal		1,540,000			1,750,000

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

(Continued)

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


	September 30,			December 31,
	2005			2004

Debt Secured by General and Refunding Mortgage Securities
5.00% SPPC Series 2001 due 2036		80,000			80,000

Subtotal		80,000			80,000

Unsecured Debt
Revenue Bonds
Nevada Power Company
5.30% NPC Series 1995D due 2011		14,000			14,000
5.35% NPC Series 1995E due 2022		13,000			13,000
5.45% NPC Series 1995D due 2023		6,300			6,300
5.50% NPC Series 1995C due 2030		44,000			44,000
5.60% NPC Series 1995A due 2030		76,750			76,750
5.90% NPC Series 1995B due 2030		85,000			85,000
5.80% NPC Series 1997B due 2032		20,000			20,000
5.90% NPC Series 1997A due 2032		52,285			52,285
6.38% NPC Series 1996 due 2036		20,000			20,000

Subtotal		331,335			331,335

Variable Rate Notes
NPC PCRB Series 2000B due 2009		15,000			15,000
NPC IDRB Series 2000A due 2020		100,000			100,000

Subtotal		115,000			115,000

Other Notes
Sierra Pacific Resources
7.803% SPR Senior Notes (New PIES) due 2012		99,141			—
7.93% SPR Senior Notes due 2007		—			240,218
7.25% SPR Convertible Notes due 2010		—			242,078
8.625% SPR Notes due 2014		335,000			335,000
6.75% SPR Senior Notes Due 2017		225,000			—

Subtotal, excluding current portion		659,141			817,296

Unamortized bond premium and discount, net		(6,048	)		(16,604	)

Nevada Power Company
Long Term Credit Facility, due 2007		50,000			—
8.2% Junior Subordinated Debentures of NPC, due 2037		122,548			122,548
7.75% Junior Subordinated Debentures of NPC, due 2038		72,165			72,165

Subtotal		244,713			194,713

Obligations under capital leases		56,541			63,021
Current maturities and sinking fund requirements		(38,804	)		(8,491	)
Other, excluding current portion		8,194			10,261

Total Long-Term Debt		3,734,822			4,081,281

TOTAL CAPITALIZATION	$	5,592,230		$	5,629,897

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

(Concluded)

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)
(Unaudited)


	September 30,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	4,129,697	$	4,015,125
Less accumulated provision for depreciation		1,141,419		1,112,335

		2,988,278		2,902,790
Construction work-in-progress		625,107		355,431

		3,613,385		3,258,221


Investments and other property, net		29,110		30,809


Current Assets:
Cash and cash equivalents		64,600		243,323
Restricted cash (Note 1)		50,311		50,311
Accounts receivable less allowance for uncollectible accounts:
2005-$34,648; 2004-$30,900		288,633		178,077
Deferred energy costs — electric (Note 1)		141,847		126,074
Materials, supplies and fuel, at average cost		45,928		44,858
Risk management assets (Note 7)		94,587		5,092
Deposits and prepayments for energy		16,518		23,091
Other		14,986		23,721

		717,410		694,547

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		387,916		375,120
Regulatory tax asset		164,318		167,221
Other regulatory assets		301,422		277,450
Risk management regulatory assets — net (Note 7)		—		3,555
Unamortized debt issuance expense		36,537		43,802
Other		38,411		32,815

		928,604		899,963

TOTAL ASSETS	$	5,288,509	$	4,883,540

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,751,301	$	1,436,788
Long-term debt		2,113,370		2,275,690

		3,864,671		3,712,478

Current Liabilities:
Current maturities of long-term debt		6,404		6,091
Accounts payable		168,553		114,242
Accounts payable, affiliated companies		14,460		3,920
Accrued interest		49,811		40,677
Dividends declared		397		399
Accrued salaries and benefits		13,992		12,780
Deferred income taxes		30,739		36,981
Risk management liabilities (Note 7)		394		3,555
Accrued taxes		2,792		2,441
Contract termination liabilities (Note 8)		213,476		211,620
Other current liabilities		44,693		27,651

		545,711		460,357

Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		366,304		308,302
Deferred investment tax credit		17,419		18,642
Regulatory tax liability		15,746		16,506
Customer advances for construction		93,083		79,243
Accrued retirement benefits		25,404		21,025
Risk management regulatory liability — net (Note 7)		90,308		—
Contract termination liabilities (Note 8)		24,498		34,847
Regulatory liabilities		173,012		171,330
Other		72,353		60,810

		878,127		710,705


TOTAL CAPITALIZATION AND LIABILITIES	$	5,288,509	$	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						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
OPERATING REVENUES:
Electric	$	675,181		$	633,609		$	1,480,699		$	1,410,067

OPERATING EXPENSES:
Operation:
Purchased power		393,414			300,290			763,096			619,329
Fuel for power generation		86,282			67,216			195,134			176,883
Deferred energy costs disallowed		—			—			—			1,586
Deferral of energy costs-net		(76,899	)		9,496			(32,965	)		91,622
Other		55,760			45,515			155,971			136,150
Maintenance		10,624			10,834			43,976			47,580
Depreciation and amortization		31,258			29,900			92,421			88,630
Taxes:
Income tax expense		42,092			43,346			40,054			37,232
Other than income		6,477			6,170			19,543			19,743

		549,008			512,767			1,277,230			1,218,755

OPERATING INCOME		126,173			120,842			203,469			191,312

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,119			487			13,017			1,769
Interest accrued on deferred energy		5,557			5,142			14,298			15,335
Disallowed merger costs		—			—			—			(3,961	)
Other income		5,238			5,335			17,600			16,464
Other expense		(1,608	)		(1,698	)		(5,001	)		(4,626	)
Income taxes		(4,578	)		(3,109	)		(12,625	)		(8,154	)

		9,728			6,157			27,289			16,827

Total Income Before Interest Charges		135,901			126,999			230,758			208,139

INTEREST CHARGES:
Long-term debt		38,587			37,736			121,729			112,570
Other		4,204			3,824			12,775			13,652
Allowance for borrowed funds used during construction		(6,362	)		(759	)		(16,154	)		(2,465	)

		36,429			40,801			118,350			123,757


NET INCOME	$	99,472		$	86,198		$	112,408		$	84,382

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 nine months ended
	September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	112,408		$	84,382
Non-cash items included in net income:
Depreciation and amortization		92,421			88,630
Deferred taxes and deferred investment tax credit		52,680			48,544
AFUDC		(29,171	)		(4,234	)
Amortization of deferred energy costs		108,480			178,451
Deferred energy costs disallowed		—			1,586
Other non-cash		(22,201	)		(23,730	)
Changes in certain assets and liabilities:
Accounts receivable		(110,556	)		(96,070	)
Deferral of energy costs		(137,048	)		(102,163	)
Materials, supplies and fuel		(1,070	)		(1,805	)
Other current assets		15,308			(5,974	)
Accounts payable		57,677			25,649
Escrow payment for terminating suppliers		—			(50,049	)
Other current liabilities		27,739			17,181
Other assets		(85,628	)		(9,701	)
Other liabilities		82,313			14,355

Net Cash from Operating Activities		163,352			165,052


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(435,413	)		(178,001	)
AFUDC and other charges to utility plant		29,171			4,234
Customer advances for construction		13,839			7,426
Contributions in aid of construction		6,971			6,127

Net cash used for utility plant		(385,432	)		(160,214	)
Investments in subsidiaries and other property — net		1,921			(177	)

Net Cash used by Investing Activities		(383,511	)		(160,391	)


CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Change in restricted cash and investments		—			2,600
Proceeds from issuance of long-term debt		50,000			130,000
Retirement of long-term debt		(212,007	)		(134,323	)
Additional investment by parent company		230,541			—
Dividends paid		(27,098	)		(39,570	)

Net Cash from (used by) Financing Activities		41,436			(41,293	)


Net Decrease in Cash and Cash Equivalents		(178,723	)		(36,632	)
Beginning Balance in Cash and Cash Equivalents		243,323			144,897

Ending Balance in Cash and Cash Equivalents	$	64,600		$	108,265


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	123,683		$	109,401

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)


	September 30,		December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,662,881	$	2,589,324
Less accumulated provision for depreciation		1,020,659		971,099

		1,642,222		1,618,225
Construction work-in-progress		55,990		50,480

		1,698,212		1,668,705


Investments and other property, net		963		999


Current Assets:
Cash and cash equivalents		74,240		19,319
Restricted cash (Note 1)		14,430		16,464
Accounts receivable less allowance for uncollectible accounts: 2005-$5,937; 2004-$5,296		120,249		142,359
Accounts receivable, affiliated companies		49,938		67,261
Deferred energy costs — electric (Note 1)		46,021		21,934
Deferred energy costs — gas (Note 1)		4,086		3,106
Materials, supplies and fuel, at average cost		36,046		31,335
Risk management assets (Note 7)		118,355		9,493
Deposits and prepayments for energy		19,083		31,676
Other		9,058		9,728

		491,506		352,675

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		137,747		151,039
Deferred energy costs — gas (Note 1)		2,899		2,491
Regulatory tax asset		111,267		112,545
Other regulatory assets		203,520		210,312
Risk management regulatory assets — net (Note 7)		—		3,118
Unamortized debt issuance expense		12,263		13,564
Other		20,430		8,872

		488,126		501,941

TOTAL ASSETS	$	2,678,807	$	2,524,320

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	720,826	$	705,395
Preferred stock		50,000		50,000
Long-term debt		962,311		994,309

		1,733,137		1,749,704

Current Liabilities:
Current maturities of long-term debt		32,400		2,400
Accounts payable		40,780		42,884
Accrued interest		24,892		9,604
Dividends declared		968		968
Accrued salaries and benefits		14,001		13,846
Deferred income taxes		20,052		17,138
Risk management liabilities (Note 7)		148		6,347
Accrued taxes		3,447		2,878
Contract termination liabilities (Note 8)		92,643		91,840
Other current liabilities		10,011		8,516

		239,342		196,421

Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		311,438		314,448
Deferred investment tax credit		22,200		23,422
Regulatory tax liability		23,562		24,069
Customer advances for construction		70,261		63,460
Accrued retirement benefits		37,105		41,558
Risk management regulatory liability — net (Note 7)		114,342		—
Contract termination liabilities (Note 8)		—		1,906
Regulatory liabilities		100,262		86,165
Other		27,158		23,167

		706,328		578,195

TOTAL CAPITALIZATION AND LIABILITIES	$	2,678,807	$	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						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
OPERATING REVENUES:
Electric	$	268,109		$	253,615		$	712,318		$	657,881
Gas		15,574			16,387			115,248			97,742

		283,683			270,002			827,566			755,623

OPERATING EXPENSES:
Operation:
Purchased power		111,409			92,481			260,498			230,577
Fuel for power generation		67,439			59,494			176,427			166,715
Gas purchased for resale		12,906			11,322			89,410			73,721
Deferral of energy costs — electric — net		(17,414	)		(3,269	)		(7,591	)		1,436
Deferral of energy costs — gas — net		(2,001	)		297			(997	)		266
Other		29,334			29,899			97,872			93,601
Maintenance		6,313			5,212			20,064			15,570
Depreciation and amortization		22,610			21,530			67,534			64,866
Taxes:
Income tax expense		10,186			9,424			19,540			9,729
Other than income		4,762			4,557			15,441			14,553

		245,544			230,947			738,198			671,034

OPERATING INCOME		38,139			39,055			89,368			84,589

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		429			230			1,229			1,513
Interest accrued on deferred energy		1,785			1,635			5,061			3,972
Disallowed merger costs		—			—			—			(1,929	)
Plant costs disallowed		—			—			—			(47,092	)
Other income		1,681			765			4,148			2,521
Other expense		(1,476	)		(1,568	)		(4,709	)		(4,123	)
Income (taxes) benefits		(782	)		(458	)		(1,997	)		14,900

		1,637			604			3,732			(30,238	)

Total Income Before Interest Charges		39,776			39,659			93,100			54,351

INTEREST CHARGES:
Long-term debt		17,307			17,307			51,933			54,022
Other		1,001			928			3,402			5,555
Allowance for borrowed funds used during construction and capitalized interest		(390	)		(364	)		(1,129	)		(2,498	)

		17,918			17,871			54,206			57,079


NET INCOME / (LOSS)		21,858			21,788			38,894			(2,728	)

Preferred Dividend Requirements		975			975			2,925			2,925

Earnings / (Deficit) applicable to common stock	$	20,883		$	20,813		$	35,969		$	(5,653	)

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 nine months ended
	September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	38,894		$	(2,728	)
Non-cash items included in net income (loss):
Depreciation and amortization		67,534			64,866
Deferred taxes and deferred investment tax credit		(548	)		(8,890	)
AFUDC		(2,358	)		(4,011	)
Amortization of deferred energy costs — electric		29,058			28,335
Amortization of deferred energy costs — gas		(486	)		3,126
Plant costs disallowed		—			47,092
Other non-cash		(4,116	)		(2,108	)
Changes in certain assets and liabilities:
Accounts receivable		39,433			11,996
Deferral of energy costs — electric		(39,853	)		(30,828	)
Deferral of energy costs — gas		(902	)		(2,905	)
Materials, supplies and fuel		(4,711	)		7,500
Other current assets		13,264			948
Accounts payable		(173	)		(9,205	)
Escrow payment for terminating supplier		—			(10,818	)
Other current liabilities		17,506			16,846
Other assets		(105,743	)		(790	)
Other liabilities		106,168			(5,090	)

Net Cash from Operating Activities		152,967			103,336


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(92,904	)		(86,233	)
AFUDC and other charges to utility plant		2,358			4,011
Customer advances for construction		6,801			5,650
Contributions in aid of construction		8,404			10,846

Net cash used for utility plant		(75,341	)		(65,726	)
Disposal of subsidiaries and other property — net		36			36

Net Cash used by Investing Activities		(75,305	)		(65,690	)


CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Decrease in short-term borrowings		—			(25,000	)
Change in restricted cash and investments		2,034			3,130
Proceeds from issuance of long-term debt		—			100,000
Retirement of long-term debt		(1,998	)		(98,989	)
Dividends paid		(22,777	)		(2,925	)

Net Cash used by Financing Activities		(22,741	)		(23,784	)


Net Increase in Cash and Cash Equivalents		54,921			13,862
Beginning Balance in Cash and Cash Equivalents		19,319			20,859

Ending Balance in Cash and Cash Equivalents	$	74,240		$	34,721


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	39,380		$	44,183

Noncash Activities:
Transfer of Regulatory Asset	$	—		$	96,470

The accompanying notes are an integral part of the financial statements

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements of Sierra Pacific Resources (SPR) include the accounts of SPR and its wholly-owned subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC) (collectively, the “Utilities”), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications (SPC) 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 and nine months ended September 30, 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.

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 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 September 30, 2005 (dollars in thousands):


		NPC		SPPC		SPPC			SPR
Description	Recovery Periods	Electric		Electric		Gas			Total
Unamortized balances approved for collection in current rates⁽¹⁾
Electric – NPC Period 2	(effective 5/03, 3 years)	$	14						$	14
Electric – NPC Period 3	(effective 4/05, 27 months)		58,887							58,887
Electric – NPC Period 4	(effective 4/05, 2 years)		82,946							82,946
Electric – SPPC Period 3	(effective 6/05, 25.5 months)				31,358					31,358
Electric – SPPC Period 4	(effective 6/05, 1 year)				17,468					17,468
Natural Gas – Period 4	(effective 11/04, 1 year)						(168	)		(168	)
LPG Gas – Period 2	(effective 11/03, 2 years)						(3	)		(3	)
LPG Gas – Period 3	(effective 11/04, 2 years)						42			42
Balances pending PUCN approval							6,289			6,289
Cumulative CPUC balance					5,682					5,682
Balances accrued since end of periods submitted for PUCN approval			156,347		46,698		825			203,870
Claims for terminated supply contracts⁽²⁾			231,569		82,562					314,131


Total		$	529,763	$	183,768	$	6,985		$	720,516


Current Assets
Deferred energy costs — electric		$	141,847	$	46,021		—		$	187,868
Deferred energy costs — gas			—		—		4,086			4,086
Deferred Assets
Deferred energy costs — electric			387,916		137,747		—			525,663
Deferred energy costs – gas			—		—		2,899			2,899

Total		$	529,763	$	183,768	$	6,985		$	720,516


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

(2)		Amounts related to claims for terminated supply contracts are discussed in Note 8 of the Condensed Notes to Consolidated Financial Statements, Commitments and Contingencies.

Restricted Cash and Investments

At September 30, 2005, restricted cash primarily represents cash restricted for 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 8, 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. Such requirements pertaining to these cash management activities were eliminated in October 2005.

Stock Compensation Plans

At September 30, 2005, SPR had several stock-based compensation plans, which are described more fully in Note 14, 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 the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” (SFAS 123) and the updated disclosure requirements set forth in SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure” (SFAS 148). Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. Had compensation cost for SPR’s nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans, consistent with the accounting provisions of SFAS No. 123, SPR’s earnings applicable to common stock would have changed to the pro forma amounts indicated below (dollars in thousands, except per share amounts):


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2005			2004			2005			2004
Earnings applicable to common stock, as reported	As reported	$	61,018		$	90,647		$	60,583		$	1,313

Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	As reported		471			844			183			1,112

Less: Total stock employee compensation expense determined under fair value based methods, net of related tax effects	Pro forma		(643	)		(894	)		(699	)		(1,262	)


Pro forma earnings applicable to common stock	Pro forma	$	60,846		$	90,597		$	60,067		$	1,163


Basic earnings per share	As reported	$	0.33		$	0.50		$	0.33		$	0.01
	Pro forma	$	0.33		$	0.49		$	0.33		$	0.01

Diluted earnings per share	As reported	$	0.33		$	0.49		$	0.33		$	0.01
	Pro forma	$	0.33		$	0.49		$	0.33		$	0.01

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 was 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.

In March 2005, the FASB issued FASB Interpretation No. FIN 47 “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (FIN 47), which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143 “Accounting for Asset Retirement Obligations”. Specifically, FIN 47 provides that an asset retirement obligation is conditional when either the timing and (or) method of settling the obligation is conditioned on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. Management is currently evaluating the effect that adoption of this interpretation will have on SPR’s and the Utilities’ financial position and results of operations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements—An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. SPR and the Utilities are currently evaluating the effect that the adoption of SFAS 154 will have on their results of operations and financial condition but do not expect it to have a material impact.

proposal would require that a tax position meet a “probable recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements. The proposal would require recognition in the financial statements of the best estimate of the effects of a tax position only if that position is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. SPR and its Utilities’ are currently reviewing the provisions of the Exposure Draft to determine the impact it may have on SPR and the Utilities’ financial position and results of operations. The proposal, if approved for final issuance, would not be effective until 2006.

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 to 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 are reported as discontinued operations in the financial statements for 2005 and 2004. Accordingly, the segment information excludes financial information of SPC. NPC’s total assets changed from the amounts reported in the 2004 10-K, mainly due to increases in Construction-Work-In-Process associated with the Chuck Lenzie Plant.

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
September 30, 2005	Electric		Electric		Electric		Gas			Other			Consolidated
Operating Revenues	$	675,181	$	268,109	$	943,290	$	15,574		$	262		$	959,126

Operating Income (Loss)	$	126,173	$	38,885	$	165,058	$	(746	)	$	(1,428	)	$	162,884


Three Months Ended	NPC		SPPC		Total
September 30, 2004	Electric		Electric		Electric		Gas			Other		Consolidated
Operating Revenues	$	633,609	$	253,615	$	887,224	$	16,387		$	304	$	903,915

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


Nine Months Ended	NPC		SPPC		Total
September 30, 2005	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	1,480,699	$	712,318	$	2,193,017	$	115,248	$	873	$	2,309,138

Operating Income	$	203,469	$	83,824	$	287,293	$	5,544	$	9,888	$	302,725


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

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

NOTE 3.REGULATORY ACTIONS

Nevada Matters

Nevada Power Company 2004 Deferred Energy Case

On November 15, 2004, NPC filed an application with the Public Utilities Commission of Nevada (PUCN) seeking recovery 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 was 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 energy rates, which are reflected in the NPC’s 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, and 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.

Nevada Power Company Base Tariff Energy Rate Update

On June 3, 2005, pursuant to newly adopted regulations allowing more frequent energy cost adjustments, NPC filed a request to increase its BTER to reflect forecasted energy costs. NPC expected the request would increase revenue by $66.9 million for the 12 month period October 1, 2005 to September 30, 2006 and more closely correlate fuel and purchased power revenues with fuel and purchased power costs. The proposed increase will not affect NPC’s operating income. The increase is intended to recoup, on a more current basis, actual fuel and purchased power costs that NPC will incur during the rate effective period.

The request represents an increase of 3.74% for the average residential customer and 3.53% for all other customer classes.

On September 27, 2005, the PUCN issued an order approving the BTER rate changes requested in NPC’s filing.

Nevada Power Company Amendments to its Integrated Resource Plan

Long Term Power Exchange

On April 18, 2005, NPC filed an application with the PUCN requesting authorization to enter into an agreement with the Southern Nevada Water Authority (SNWA) that will allow NPC to dispatch SNWA’s 25% capacity ownership in the Silverhawk generating plant. The eight year agreement gives NPC the ability to use 125MW of the Silverhawk capacity and in return NPC will supply 75MW of firm power to SNWA.

On May 19, 2005, the PUCN approved the Power Exchange Agreement, which became effective June 1, 2005.

Silverhawk Plant Acquisition and Clark Generating Unit Retirements

Silverhawk Plant Acquisition — On June 29, 2005, NPC filed an application with the PUCN for approval to purchase the remaining 75% interest in the 560MW gas fired Silverhawk power plant from Pinnacle West Capital Corp, Pinnacle West Energy Corp and GenWest, LLC. The Silverhawk generating plant is located 25 miles northeast of Las Vegas and is near NPC’s Lenzie Power plant. NPC also made concurrent filings requesting approval of an interim Silverhawk power purchase agreement and approval to issue $210 million of debt financing to close the transaction.

Clark Generating Unit Retirements — NPC has also requested approval to retire and recover the associated retirement and decommissioning costs for the Clark Generating Station units 1, 2 and 3. NPC requested approval to set up regulatory asset accounts to capture the Clark retirement and decommissioning costs.

The Staff, Bureau of Consumer Protection (BCP) and NPC filed a negotiated settlement stipulation on these matters with the PUCN on September 9, 2005. The stipulation requests the PUCN approve the following significant terms:

	•		The Interim Purchased Power Agreement (in effect from October 1, 2005 and until final approvals of acquisition) is prudent and NPC may recover all just and reasonable costs through the deferred energy accounting process.

	•		The terms and conditions of the Silverhawk acquisition agreement are just and reasonable and NPC may recover all just and reasonable acquisition costs in general rates. The stipulation recognizes the $221.4 million acquisition cost as estimated by NPC.

	•		NPC is authorized to issue up to $210 million of long term financing through December 31, 2006 for the Silverhawk facility acquisition or other lawful public utility purposes.

•

It is prudent for NPC to retire the Clark Generating Station Units 1, 2, and 3 and for NPC to commence the permitting process for replacement units at that site.

On September 23, 2005, the PUCN issued its order approving the stipulation.

Not included in the above stipulation was NPC’s requested accounting treatment for retirement and decommissioning costs. On September 13, 2005 NPC filed an amended application requesting 1) authorization to set up a regulatory asset account for the net book value and decommissioning costs for the Clark Units 1, 2 and 3 and that any balance in that account be included in rate base in NPC’s next general rate case with a four year amortization schedule, 2) authorization to use decremental operations and maintenance costs associated with the shutdown of the Mohave generating station to offset the incremental operations and maintenance costs resulting from the addition of the Lenzie and Silverhawk generating units.

The PUCN has scheduled a hearing for November 16-17, 2005 and NPC expects a decision will be issued in the fourth quarter 2005.

Sierra Pacific Power Company 2005 Electric Deferred Energy Case

On January 14, 2005, SPPC filed an application with the PUCN seeking recovery 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 $27.7 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 BTER or going-forward energy rate.

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. The updated forecasted 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 BCP filed written direct testimony in this case. The testimony recommended full recovery of the deferred balance after a $576 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 issued its order on May 17, 2005 granting $27.1 million deferred expense recovery ($27.7 million requested less $.6 million), modifying the amortization period from the two years requested to one year and approving a BTER rate based on the historical costs methodology as provided for in the Nevada Administrative Code.

Sierra Pacific Power Company Electric Base Tariff Energy Rate Update

On July 1, 2005, SPPC filed a request to increase its BTER to reflect forecasted energy costs. The request was expected to increase revenue by $32.3 million for the period October 1, 2005 to September 30, 2006 and would more closely correlate fuel and purchased power revenues with fuel and purchased power costs. The proposed increase will not affect SPPC’s operating income. The increase is intended to recoup, on a more current basis, actual fuel and purchased power costs that SPPC will incur during the rate effective period.

The request represents an increase of 3.7% for the average customer. SPPC agreed to a November 1, 2005 effective date due to procedural requirements.

The PUCN Staff filed testimony that would increase SPPC’s request. The Staff’s recommended BTER would increase rates by 10.9% and increase revenues by $95.2 million for the 12 month period.

On October 27, 2005 the PUCN voted to approve a new electric BTER effective November 1, 2005. The new rate represents a 7.3% overall electric rate increase and is expected to produce $64 million additional revenues during the following 12 months.

Sierra Pacific Power Company 2005 Gas Deferred Energy Rate Case and Base Tariff Energy Rate Filing

Newly enacted regulations require SPPC to account for gas purchases to serve its gas customers in the same manner as it does for its electric customer fuel and power purchases. On May 13, 2005, SPPC filed a gas deferred energy rate case requesting recovery of $6.9 million of deferred energy costs. The filing requests a two-year amortization of the deferred energy balance which represents a 3.2% average increase for all customers.

On July 1, 2005 SPPC filed a proposed gas BTER, which represents an average increase of 19.5% for all customer classes. The estimated BTER revenue will not change SPPC’s operating income.

The PUCN Staff testimony recommended full recovery of the deferred period gas expenditures. The PUCN Staff filed testimony recommending a higher BTER that would increase rates by 28.7% overall and would add $42.4 million to current revenues.

On October 27, 2005 the PUCN voted to approve recovery of $6.9 million of deferred energy costs with a one year amortization and set a new gas BTER rate, both effective on November 1, 2005. The new BTER is expected to produce $34.1 million additional revenues during a 12 month period. The combined increases represent a 25.3% overall gas rate increase.

California Matters

Sierra Pacific Power Company General Rate Case

On June 3, 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue from approximately 40,000 California customers. The request represents a 12.7% average increase. SPPC has requested that the new rates become effective on January 1, 2006.

On September 7, 2005, a pre-hearing conference was held and a procedural schedule was established. Hearings are scheduled for January 23 through 27, 2006. The earliest rates will become effective is July 1, 2006.

FERC Matters

Sierra Pacific Power Company 2004 Transmission Rate Case

On October 1, 2004, SPPC 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. On May 6, 2005, the FERC issued an order approving the negotiated settlement.

NOTE 4.SHORT-TERM BORROWINGS

On June 20, 2005, SPR issued and sold $140,860,000 of its Series A Floating Rate Senior Notes, due November 16, 2005, and $99,140,000 of its Series B Floating Rate Senior Notes, due November 16, 2005 (collectively, the “Floating Rate Notes”). The Series A Floating Rate Notes initially bore interest at a rate equal to 3-month LIBOR plus 2.00%, and the Series B Floating Rate Notes bear interest at a rate equal to 3-month LIBOR plus 1.00%. On August 15, 2005, the interest rate on the Series A Floating Rate Notes was reduced to a rate equal to 3-month LIBOR plus 1.00%. Of the proceeds from this issuance, $230.5 million was used to make an equity contribution to NPC and the balance was used for general corporate purposes. NPC used the equity contribution to redeem approximately $210 million of General and Refunding Mortgage Notes.

SPR may redeem, at any time, all or a part of the Floating Rate Notes, without premium or penalty, upon not less than three, nor more than thirty, days’ notice. Subject to certain limitations, additional Floating Rate Notes may be issued from time to time; provided, however, that the aggregate principal amount of Floating Rate Notes outstanding at any time may not exceed $240,000,000. SPR expects to repay its short-term floating rate senior notes with the $240 million of proceeds it will receive on November 15, 2005 from the settlement of the common stock purchase contracts associated with its PIES issued on November 16, 2001 (the “Old PIES”) and its PIES issued on May 24, 2005 (the “New PIES”).

NOTE 5.LONG-TERM DEBT

As of September 30, 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.		SPR
	NPC			SPPC			and Other Subs.		Consolidated
2005	$	4,476		$	345		$	—	$	4,821
2006		6,509			52,400			—		58,909
2007		55,950			2,400			—		58,350
2008		7,066			322,400			—		329,466
2009		184,638			600			—		185,238

		258,639			378,145			—		636,784
Thereafter		1,866,499			617,250			659,141		3,142,890

		2,125,138			995,395			659,141		3,779,674
Unamortized (Discount Amount)		(5,364	)		(684	)		—		(6,048	)

Total	$	2,119,774		$	994,711		$	659,141	$	3,773,626

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)

PIES Transaction

On April 15, 2005, SPR commenced an offer to exchange its Old PIES (Premium Income Equity Securities) for new New PIES plus an exchange fee of $0.125 in cash for each Old PIES tendered. On May 24, 2005, the tender offer was completed with 1,982,822 or about 41% of the 4,804,350 Old PIES outstanding tendered for exchange. The remaining 2,821,528 Old PIES remained outstanding. The New PIES are similar to the Old PIES except that the New PIES (i) allow for 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.

On May 24, 2005, as a component of the New PIES, SPR issued $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the Old PIES. SPR successfully remarketed these notes on June 14, 2005. In connection with the remarketing, the interest rate of the senior notes issued in connection with the New PIES was reset to 7.803% per annum, effective on and after June 14, 2005. The remarketed senior notes will mature on June 15, 2012. The proceeds of the remarketing of the senior notes were used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities will serve as substitute collateral for the senior notes component of the New PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S. treasury securities upon maturity will be used to provide the consideration necessary to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the New PIES through November 15, 2005.

On August 10, 2005, the remaining $141,076,000 aggregate principal amount of its 7.93% Senior Notes associated with the Old PIES were remarketed. On August 15, 2005, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (described below under the headingPrivate Placement) to purchase all of the 7.93% Senior Notes that were remarketed. As with the May 2005 remarketing of the 7.93% Senior Notes, the proceeds of this remarketing were used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities will serve as substitute collateral for the senior notes component of the Old PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S. treasury securities upon maturity will be used to provide the consideration necessary to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the Old PIES through November 15, 2005.

Convertible Notes

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of its $300 million outstanding ($248 million carrying value) 7.25% Convertible Notes due 2010 (7.25% Notes) to convert their 7.25% Notes to shares of SPR common stock. The conversion offer, which was extended to September 2, 2005, was accepted by 100% of the holders of the 7.25% Notes. Under the terms of the offer, for each $1,000 in liquidation amount of 7.25% Notes tendered, holders received the conversion consideration and 219.1637 shares of common stock. The consideration offered was an amount paid in cash equal to $180 per $1,000 principal amount of 7.25% Notes validly surrendered for conversion plus an amount equivalent to the

interest that would have accrued thereon from and after August 14, 2005 (which was the last interest payment date on the 7.25% Notes prior to the expiration of the offer). On September 8, 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were issued to the holders in exchange for the 7.25% Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” the $54 million cash payment was expensed during the third quarter of 2005.

Private Placement

On August 12, 2005, SPR conducted a private placement of $225 million 6.75% Senior Notes due 2017. The proceeds were used to repurchase approximately $141 million 7.93% Senior Notes associated with the Old PIES, pay approximately $54 million in premiums associated with the conversion of the 7.25% Notes and fund the associated fees and expenses; and provide additional liquidity to SPR.

Financing Transactions (NPC)

As of September 30, 2005 NPC had $50 million in loans outstanding under its existing revolving credit facility. The loan was paid in full on October 28, 2005.

On July 14, 2005, NPC redeemed $87,500,000 aggregate principal amount of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (the “Series E Notes”) and $122,500,000 aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013 (the “Series G Notes”). These redemptions constituted 35% of the principal amount outstanding of each of the Series E Notes and the Series G Notes. The Series E Notes were redeemed at a redemption price equal to $1,108.75 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $9.5 million. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt. NPC paid for the redemptions with the proceeds of an equity contribution of approximately $230.5 million from SPR, as discussed in Note 4, Short-Term Borrowings.

Financing Transactions (SPPC)

On November 4, 2005, SPPC amended and restated its existing secured $75 million revolving credit facility, maturing in October 2007, increasing the size of the facility to $250 million and extending the maturity to November 2010 and changing the Administrative Agent to Wachovia Bank, National Association; however, the total amount of the credit facility will be reduced by $200 million in November 2006 unless SPPC obtains long-term PUCN authority for this amount prior to such date. The previous facility was secured by General and Refunding Mortgage bonds, and the amended facility will also be secured by General and Refunding Mortgage bonds.

As of September 30, 2005 SPPC had no borrowings under its existing revolving credit facility.

NOTE 6.COMMON STOCK AND OTHER PAID IN CAPITAL

Common Stock Transactions

Convertible Notes Transaction

On September 8, 2005, in conjunction with the induced conversion of the convertible notes, SPR issued 65,749,096 shares of common stock, plus cash in lieu of fractional shares, to the holders of its convertible notes in exchange for the Notes. See Note 5, Long-Term Debt for further discussion of the induced conversion of the convertible notes.

PIES Transaction

On November 15, 2005, SPR expects to issue common stock in connection with the settlement of the PIES. Given the current balance of 4,804,350 PIES outstanding, approximately 17,344,183 shares of SPR common stock will be issued at the settlement date of November 15, 2005, based on the 20 day average closing price as of November 2, 2005. For further discussion of the PIES transactions, see Note 5 above and Note 7, Long-Term Debt of the 2004 10-K. The amount of shares of common stock outstanding will be approximately 200,766,810 upon settlement of the outstanding PIES.

NOTE 7.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. 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 increase in risk management assets as of September 30, 2005 compared to December 31, 2004 is due to favorable positions on natural gas options held by the Utilities as a result of increasing prices.

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):


	September 30, 2005									December 31, 2004
	SPR			NPC			SPPC			SPR		NPC		SPPC
Risk management assets	$	212.9		$	94.6		$	118.3		$	14.6	$	5.1	$	9.5
Risk management liabilities	$	.5		$	.4		$	.1		$	9.9	$	3.6	$	6.3
Risk management regulatory assets (liabilities)	$	(204.6	)	$	(90.3	)	$	(114.3	)	$	6.7	$	3.6	$	3.1

Also included in risk management assets were $7.8 million, $3.9 million, and $3.9 million in payments for gas options by SPR, NPC, and SPPC, respectively, at September 30, 2005.

NOTE 8.COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Mohave Generation Station

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.

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.

Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE’s share of Mohave. 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.

Tribes, it is not the intention of SCE and other owners to proceed with the installation of required pollution control equipment at this time. The owners intend to suspend operation of the plant by January 1, 2006, pending resolution of these issues. It is the owners’ intent to preserve their ability to restart the plant at a later date should these issues be resolved, and economic analysis at that time support such a decision. See further discussion of issues related to Mohave below in Regulatory Contingencies.

Reid Gardner Station

In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Pond construction and lining costs to satisfy the NDEP order are estimated at approximately $33 million, of which, approximately $21.6 million has been spent through September 30, 2005.

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. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and on December 2, 2004 issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. On July 20, 2005, NDEP issued new Notices of Alleged Violations (NOAVs). In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. On July 26, 2005 NPC received a letter from the EPA requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has responded to the EPA information request.

NPC is engaged in an ongoing dialogue and settlement discussions with NDEP and the EPA regarding the NOAVs. Management cannot at this time reasonably estimate the amount of any potential monetary penalty, nor the cost of additional systems and equipment changes that may be required to achieve a settlement of the alleged violations.

Clark Station

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. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time.

NEICO

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 along 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.

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); FERC hearings consisting of the FERC Early Termination Proceeding, 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 (as defined below) entered by the Bankruptcy Court related to the bankruptcy case of Enron, 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 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.

On July 20, 2005, the FERC issued an Order in the Gaming and Partnership Show Cause Proceeding, which among other things, required several parties, including Nevada Power Company, Sierra Pacific Power Company and Enron to participate in a FERC settlement process. This FERC mandated settlement process remains active.

On August 8, 2005, President Bush signed the Domenici Barton Energy Policy Act into law (the “Energy Bill”). The Energy Bill contains language that relates to the Utilities’ disputes with Enron over termination payments Enron claims are owed to them arising from forward power purchase contracts terminated by Enron in 2002. The Energy Bill grants FERC exclusive jurisdiction over the determination of whether any such payments are unjust, unreasonable or contrary to the public interest.

On August 19, 2005, the Bankruptcy Court entered an Order approving a Stipulation by which the Utilities and Enron agreed to a standstill of the Bankruptcy Court proceeding until the earlier of (1) FERC lifting its July 20, 2005 stay under FERC Gaming and Partnership Show Cause Proceeding or (2) FERC approving the settlement agreement between the California parties and Enron discussed under FERC Gaming and Partnership Show Cause Proceeding.

A full description of all legal proceedings and pending matters related to the Enron litigation follows.

Bankruptcy Court Judgment

On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy case in the 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.

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 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. 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.

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.

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

and Enron agreed to a standstill of the Bankruptcy Court proceeding until the earlier of (1) FERC lifting its July 20, 2005 stay (discussed below under FERC Gaming and Partnership Show Cause Proceeding) or (2) FERC approving the settlement agreement between the California parties and Enron (discussed under FERC Gaming and Partnership Show Cause Proceeding below). 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

On June 25, 2003, FERC issued orders in two separate cases involving Enron, among others, 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 retroactively 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. In that order, the FERC stated that Enron’s profits under the terminated power contracts fell within the scope of that proceeding. On July 20, 2005, the FERC issued an order in the Gaming and Partnership Show Cause Proceeding involving Enron, among others, suspending the trial schedule, including the September 7, 2005 trial date, pending FERC review of a recent settlement agreement between the California parties and Enron. The order provides that the trial in this proceeding will convene within seven weeks following FERC’s review of the proposed settlement. FERC also ordered Enron not to take any action to move forward the Bankruptcy Court proceeding, and ordered it to join in any request for postponement of any filing or action in the Bankruptcy Court proceeding. In addition, FERC ordered the remaining parties, including NPC and SPPC, to participate in settlement negotiations.

The FERC proceeding focuses on Enron’s illicit trading activity in California with various counterparties, including the People of the State of California, California state entities, California utilities and other non-Californian entities (including NPC and SPPC). NPC and SPPC are unable at this time to predict the outcome of the ongoing settlement negotiations, or, if settlement negotiations prove unsuccessful, the outcome of the trial.

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 settlements with Duke Energy Trading and Marketing and Reliant Energy Services, Inc., but have been 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 and Duke Antitrust Litigation

Reliant Energy Services, Inc. (Reliant) served a cross-complaint against NPC and SPPC and Duke Energy Trading and Marketing, LLC (Duke) served a cross-complaint against Sierra Pacific Resources in the wholesale electricity antitrust cases on April 22, 2002 and April 23, 2002, respectively. These 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 and Duke 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. Despite efforts by various cross-defendants to remove the case to federal court and following an appeal with the Ninth Circuit Court of Appeals, the case was ultimately remanded back to the Superior Court of the State of California in May 2005. On October 3, 2005, the Superior Court entered an Order accepting a stipulation taking the Duke and Reliant demurrer off the calendar pending approval of their proposed settlements. A status conference is currently scheduled for November 10, 2005. The case is currently active and a scheduling order has been set. SPR maintains that Duke agreed to dismiss its cross-complaint pursuant to settlement and release agreement dated June 4, 2002 and that Reliant has also agreed to dismiss its cross-claim. SPR, NPC and SPPC believe they should have no liability regarding either 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 arbitration provisions in various power supply contracts that were terminated by MSCG in April 2002. MSCG requested that the arbitrator award $25 million for termination payments, pending the outcome of the subject power supply contract disputes with NPC. NPC claimed it did not owe payment under the contracts on various grounds, including breach by MSCG in terminating the contracts and lack of jurisdiction by the arbitrator. In March 2003, the arbitrator dismissed MSCG’s demand for arbitration and agreed that the issues raised by MSCG and NPC’s contract defenses were not arbitrable.

NPC filed a complaint for declaratory relief in the U.S. District Court, District of Nevada seeking a declaration stating NPC is not liable for any damages resulting from MSCG’s termination of the power supply contracts. On April 17, 2003, MSCG filed an answer and a counterclaim seeking $25 million in termination payments. Furthermore, MSCG filed a complaint against NPC at the FERC seeking termination payments from NPC pending resolution of the civil case. In addition, MSCG filed a motion to intervene in the Section 206 action commenced by NPC against Enron at the FERC, which motion the FERC denied. On October 23, 2003, NPC filed a motion to stay the District Court proceedings seeking declaratory relief, pending guidance on applicable legal principles to be provided by the FERC in connection with NPC’s litigation against Enron regarding the exercise of default and early termination rights. In February, 2004, the District Court granted NPC’s motion. In August, 2004, upon motion by NPC, the District Court continued the stay. In February, 2005, the Judge ordered the case to go forward, at which time NPC filed a motion for summary judgment. In March, 2005, MSCG similarly filed for summary judgment. The District Court denied both summary judgment motions, stating that there are serious factual questions that must be addressed about the reasonableness of MSCG’s termination of the 28 contracts, which determination will be made upon completion of discovery (currently scheduled for November 30, 2005). A court ordered settlement conference was conducted in the third quarter of 2005 but did not result in a settlement. The Court further ordered that NPC pay MSCG for the approximately $1.8 million (plus interest) for power delivered prior to the termination. NPC complied with the Court’s order and paid for the power delivered. The termination dispute for power not-delivered is still ongoing and trial is scheduled for January, 2006. At this time, NPC is unable to predict the outcome or timing of the matter.

El Paso Merchant Energy

On September 25, 2002, El Paso Merchant Energy (EPME) terminated all forward energy contracts between NPC and EPME for alleged defaults under the Western Systems Power Pool Agreement (WSPPA). Specifically, EPME alleges NPC failed to pay full contract price 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 for power delivered from May 15 to September 15, 2002, and approximately $10 million in alleged mark to market damages for future undelivered power. The amount presently claimed by EPME is $42 million, which includes interest. NPC asserts that, under the WSPPA, EPME’s wrongfully terminated the contracts and is owed liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012, resulting in net payments due to NPC. The precise net amount due to NPC is dependent upon the manner in which the termination payments are calculated.

In June 2003, EPME demanded mediation of its termination payment claim. The mediation was unsuccessful.

On July 25, 2003, NPC commenced an action against EPME and several affiliates in the Federal District Court, District of Nevada for damages and declaratory relief resulting from breach of these purchase power contracts. EPME filed a motion for summary judgment in April 2005. The court denied EPME’s motion for summary judgment in August 2005. Trial is scheduled for February 7, 2006. 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) which includes three coal-fired electrical generating units and is located in Northern Arizona. Other participants in Navajo, are 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).

On October 15, 2004, coal supplier Peabody Western Coal Co. (Peabody) filed a complaint in Missouri State Court in St. Louis, seeking reimbursement of royalties and other costs and damages for alleged breach of the coal supply agreement for the Navajo plant. In January 2005, the Joint Owners were served and operating agent, Salt River, has engaged counsel and is defending the suit on behalf of the Joint Owners. NPC believes Peabody’s claims are without merit and intends to contest these.

On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a motion to remand the case back to state court in St. Louis, Missouri. The parties are presently conducting limited discovery in Federal court in connection with the motion. NPC is unable to predict the outcome of the decision.

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 Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company for the flume and dam. 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 insurers filed a motion for summary judgment on the coverage issue in May 2005. SPPC filed its opposition in June 2005 and the motion is currently pending before the District Court. The case is not yet set for trial. 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.

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 have had or, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations, or cash flows. SPR and their subsidiaries have entered into several contracts with contingency legal fee arrangements. The outcome of which are dependent upon the outcome of the associated cases.

Contract Termination Liabilities

At September 30, 2005, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” were approximately $238 million and $92.6 million, respectively, of charges for terminated power supply contracts and associated interest. Correspondingly, pursuant to deferred energy accounting provisions, included in NPC and SPPC deferred energy balances as of September 30, 2005, were approximately $232 million and $83 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 Contingencies

Nevada Power Company

Mohave Generation Station

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

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. See the Environmental section above for further discussion on Mohave’s environmental issue.

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 in 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 31, 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 effect on NPC’s and SPR’s financial position, results of operations, and future cash inflows. As of September 30, 2005, the net book value of Mohave is approximately $30.0 million.

Clark Generating Station

NPC has requested approval to retire and recover the associated retirement and decommissioning costs for the Clark Generating Station units 1, 2 and 3. NPC requested approval to set up regulatory asset accounts to capture the Clark retirement and decommissioning costs. The Staff, the Bureau of Consumer Protection (BCP) and NPC filed a negotiated settlement stipulation to the PUCN on September 9, 2005. The stipulation requests the PUCN approve prudency for NPC to retire the Clark Generating Station Units 1, 2, and 3 and for NPC to commence the permitting process for replacement units at that site. On September 23, 2005, the PUCN issued its order approving the stipulation.

Not included in the above stipulation was NPC’s requested accounting treatment for retirement and decommissioning costs. On September 13, 2005 NPC filed an amended application requesting authorization to set up a regulatory asset account for the net book value and decommissioning costs for the Clark Units 1, 2 and 3 and that any balance in that account be included in rate base in NPC’s next general rate case with a four year amortization schedule. The PUCN has scheduled a hearing for November 16-17, 2005 and NPC expects a decision will be issued in the fourth quarter 2005.

NPC retired the Clark units as of September 30, 2005. The net book value of the Clark station retired was approximately $14.1 million. In accordance with regulatory accounting, the amount will remain in net plant in service, until accounting treatment has been ordered from the PUCN, as discussed above.

NOTE 9.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, and the non-employee director stock plan.

For the three months and nine months ended September 30, 2004, SPR had outstanding $300 million in 7.25% convertible notes due 2010 that were 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 met the criteria of a participating security in the calculation basic EPS, and were 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.

Emerging Issues Task Force (Issue 03-6), “Participating Securities and the Two-Class Method under FASB Statement No. 128”, requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result is dilutive. The “two-class” method was used to calculate basic EPS for the three months and nine months ended September 30, 2004 and September 30, 2005. On September 8, 2005 SPR issued approximately 65.7 million shares of common stock in connection with the early conversion of the 7.25% Convertible Notes. See Note 5, Long-Term Debt for discussion of the conversion of the convertible notes.

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


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
Basic EPS
Numerator ($000)
Income from continuing operations	$	62,127		$	91,749		$	63,636		$	8,007
Loss from discontinued operations	$	(134	)	$	(127	)	$	(128	)	$	(3,769	)

Earnings applicable to common stock	$	44,372		$	58,100		$	40,594		$	841
Earnings applicable to convertible notes	$	16,646		$	32,547		$	19,989		$	472

Earnings used for basic calculation	$	61,018		$	90,647		$	60,583		$	1,313

Denominator
Weighted average number of common shares outstanding		133,350,770			117,368,001			122,766,016			117,296,081
Shares issuable for Convertible Notes		50,026,486			65,749,110			60,450,634			65,749,110

		183,377,256			183,117,111			183,216,650			183,045,191


Earnings (Deficit) Per Share Amounts
Income from continuing operations	$	0.34		$	0.50		$	0.35		$	0.04
Loss from discontinued operations	$	—		$	—		$	—		$	(0.02	)

Earnings applicable to common stock	$	0.33		$	0.50		$	0.33		$	0.01
Earnings applicable to convertible notes	$	0.33		$	0.50		$	0.33		$	0.01

Diluted EPS
Numerator ($000)
Income from continuing operations	$	62,127		$	91,749		$	63,636		$	8,007
Loss from discontinued operations	$	(134	)	$	(127	)	$	(128	)	$	(3,769	)

Earnings applicable to common stock	$	61,018		$	90,647		$	60,583		$	1,313

Denominator (1)
Weighted average number of shares outstanding before dilution		133,350,770			117,368,001			122,766,016			117,296,081
Stock options		46,329			27,307			40,434			22,051
Executive long term incentive plan — restricted shares		284,181			169,184			316,888			150,419
Non-Employee Director stock plan		34,514			16,252			28,717			14,525
Employee stock purchase plan		9,920			6,381			5,234			3,190
Convertible Stock		50,026,486			65,749,110			60,450,634			65,749,110

		183,752,200			183,336,235			183,607,923			183,235,376

Earnings (Deficit) Per Share Amounts
Income from continuing operations	$	0.34		$	0.50		$	0.35		$	0.04
Loss from discontinued operations	$	—		$	—		$	—		$	(0.02	)

Earnings applicable to common stock	$	0.33		$	0.49		$	0.33		$	0.01


(1)		The denominator for diluted EPS does not include stock equivalents resulting from the conversion of SPR’s PIES and options issued under the Nonqualified stock option plan for periods ended September 30, 2005 and 2004 due to conversion prices being higher than market prices or due to a future maturity date . 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 the three and nine months ending September 30, 2005 and 2004. Under the nonqualified stock option plan for the three and nine months ended September 30, 2005, 364,688 and 633,902 shares, respectively, would be included and 1,178,505 and 1,226,730 shares, respectively, for the three and nine month periods ending September 30, 2004.

NOTE 10.DISCONTINUED OPERATIONS AND DISPOSAL AND IMPAIRMENT OF LONG-LIVED ASSETS

Sierra Pacific Communications

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

SPC formed a limited liability company with Touch America, INC. (TAI) named Sierra Touch America LLC (STA) in 2000, to further the development of the Long Haul System (System). In September 2002, SPC and TAI entered into an agreement whereby SPC redeemed its membership interest in STA and acquired fiber optic assets in the System and an indemnity for System liabilities. In June 2003, TAI and all its subsidiaries (including STA) filed a petition for Chapter 11 bankruptcy protection. SPC pursued litigation TAI’s bankruptcy case to resolve its obligations to and claims against, TAI and its affiliates. On July 28, 2004, SPC entered into a settlement agreement with TAI, STA and AT&T (the Settlement). The bankruptcy court approved TAI’s plan of liquidation and the Settlement on October 6, 2004.

The Settlement provided SPC with one remaining duct and associated occupancy right in the System and allowed SPC to complete the transfer and sale of the duct, which was negotiated under a 2002 contract with Qwest Communications (Qwest) for $20 million. Upon reaching the Settlement management had the ability and plan to dispose of SPC’s Long Haul Assets, and in accordance with SFAS 144 Accounting for the Disposition or Impairment of Long-Lived Assets, reported the Long Haul Assets as Discontinued Operations. SPC received $10 million of the amount in 2003, which is included in current liabilities of discontinued operations until the consummation of the deal between Qwest and SPC is completed.

Due to certain conditions in clearing “right of way” requirements from the BLM, SPR has been delayed in consummating the sale of the long haul assets to Qwest. In late October 2005, the “right of way” requirements were cleared and the assets were presented to Qwest per the terms of “the Amended Sale Agreement”. Qwest rejected SPC’s request to tender under the Amended Sale Agreement alleging primarily that SPC had failed to deliver a timely completion notice. SPC denies these claims and believes Qwest is still obligated to perform under the contract terms. Currently, SPC is evaluating the effect in the fourth quarter of Qwest’s rejection to the tender offer in accordance with the guidelines under SFAS No. 144.

NOTE 11.GOODWILL AND OTHER MERGER COSTS

SPR’s Consolidated Balance Sheet as of September 30, 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 current 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. If the PUCN were to disallow any portion of the $19 million of goodwill assigned to SPPC’s gas business, that portion would be subject to impairment testing under the provisions of SFAS No. 142, “Accounting for Goodwill, Other Intangible Assets” (SFAS No. 142).

The approximate $4 million of goodwill assigned to SPR’s unregulated operations were subject to impairment review under the provisions of SFAS No. 142. SFAS No. 142 provides that an impairment loss 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.

NOTE 12.PENSION AND OTHER POST-RETIREMENT BENEFITS

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


	Three Months Ended September 30,												Nine Months Ended September 30,
	2005			2004			2005			2004			2005			2004			2005			2004
							Other Postretirement												Other Postretirement
	Pension Benefits						Benefits						Pension Benefits						Benefits
Service cost	$	4,620		$	4,497		$	820		$	779		$	13,861		$	13,491		$	2,461		$	2,338
Interest cost		8,062			7,568			2,465			2,382			24,186			22,705			7,394			7,146
Expected return on plan assets		(9,042	)		(7,658	)		(903	)		(1,034	)		(27,125	)		(22,974	)		(2,708	)		(3,101	)
Amortization of prior service cost		428			428			16			16			1,285			1,285			47			47
Amortization of Transition Obligation		—			—			242			242			—			—			727			727
Amortization of net (gain)/loss		1,614			2,243			1,059			1,157			4,841			6,728			3,176			3,470


Net periodic benefit cost	$	5,682		$	7,078		$	3,699		$	3,542		$	17,048		$	21,235		$	11,097		$	10,627

It was previously disclosed in Note 12, Retirement Plan and Post-retirement Benefits, of the combined SPR, NPC, and SPPC Annual Report 10-K, as of December 31, 2004, that there would be no employer contributions made in 2005 for pension benefits and $0.2 million for other postretirement benefits; however, the company has concluded that it would be beneficial to contribute $15 million to the pension plan and $15 million to the other postretirement benefits plan in 2005 based on actuarial projections. During the nine months ended September 30, 2005, $15 million was paid toward the pension plan and approximately $11 million toward the other postretirement benefits plan.


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

Forward-Looking Statements and Risk Factors

The information in thisForm 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. 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)		whether NPC’s and SPPC’s (the Utilities) will be able to continue to obtain fuel, power and natural gas from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, sharp increases in the prices for fuel, power and/or natural gas, or a ratings downgrade;

	(2)		unfavorable rulings in rate cases filed and to be filed by the Utilities with 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)		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;

	(4)		whether the Utilities will be successful in obtaining Public Utilities Commission of Nevada’s (the “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;

	(5)		a requirement for the Utilities to pay Enron Power Marketing, Inc. (Enron) for amounts allegedly due under terminated purchase power contracts and whether the Utilities will be permitted by the PUCN to recover any such costs in rates;

	(6)		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 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;

	(7)		whether the Utilities will be able to continue to pay SPR dividends under the terms of their respective financing and credit agreements, a stipulation agreement with Enron, 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;

	(8)		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;

	(9)		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;

	(10)		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;

	(11)		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;

	(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 laws or regulations, 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 SPR or 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:

	•		Results of Operations

	•		Analysis of Cash Flows

	•		Liquidity and Capital Resources

	•		Regulatory Proceedings (Utilities)

	•		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 credit rating to the Utilities’ secured debt.

Since the beginning of 2004, SPR and the Utilities have completed a series of financings that have extended maturities, reduced interest costs, improved their capital structure, increased liquidity and enhanced the credit of SPR and the Utilities. As a result, Moody’s Investor Service improved the credit ratings of SPR and the Utilities, Standard and Poor’s changed our credit outlook to “positive” from “negative,” and Fitch commenced credit coverage at the same equivalent ratings as Moody’s. SPR and the Utilities will continue to look for opportunities to improve its financial strength and improve its credit quality. Financing activities during 2005 are discussed briefly under Improved Debt Profile and in detail in Liquidity and Capital Resources, Financing Transactions.

The population growth within the Utilities’ service territory has been and is projected to continue 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 build or obtain generation, transmission and energy supply contracts. These commitments are subject to the approval of the Public Utilities Commission of Nevada (PUCN), in some cases the Federal Energy Regulatory Commission (FERC), and, additionally for SPPC, the California 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. Energy sales 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. SPPC’s electric system peak also typically occurs in the summer, but has 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.

NPC’s revenues for the nine months ended September 30, 2005 increased from the same period in 2004 primarily as a result of customer growth. This increase was partially offset by an energy rate decrease that went into effect April 1, 2005. During the month of July 2005, NPC experienced five days of peak system usage due to hotter weather temperatures in the Clark County area. NPC’s net income for the nine months ended September 30, 2005 increased compared to the same period in 2004, primarily as a result of increased revenues.

SPPC’s electric and gas revenues for the nine months ended September 30, 2005 increased compared to the same period in 2004 primarily as a result of increased customer rates and usage. SPPC’s net income for the nine months ended September 30, 2005 increased compared to the same period in 2004 primarily as a result of increased revenues and the disallowance of a portion of SPPC’s costs associated with Pinon Pine recorded in the second quarter of 2004.

SPR’s net income from continuing operations for the nine months ended September 30, 2005 increased compared to the same period in 2004. SPR’s net income from continuing operations for the nine months ended September 30, 2005 was affected by approximately $35 million (after taxes) in costs associated with the early conversion of the convertible debt.

However, due to items recorded in the second quarter of 2004 that did not recur in 2005 SPR’s net income from continuing operations for the nine months ended September 30, 2005 compared favorably to the same period in 2004. These items were the write-off of goodwill associated with the 1999 merger of SPR and NPC, disallowed merger costs, tender fees paid in connection with extinguishment of certain debt and the disallowance of a portion of SPPC’s costs associated with Pinon Pine.

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. In May 2005, the PUCN issued its order granting recovery of $27.1 million of the $27.7 million of deferred expenses requested. NPC filed to increase its Base Tariff Energy Rate (BTER) on June 3, 2005 intending to recoup on a more current basis, actual fuel and purchased power costs. In September 2005, the PUCN approved the rate change request effective October 2005. In the third quarter of 2005, SPPC filed a gas deferred energy rate case and for an increase to its electric and gas BTER. In October 2005, the PUCN approved the filings as requested. In October 2005, SPPC filed a gas and electric general rate case. The PUCN is not expected to rule on SPPC’s general rate case until 2006.

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. In addition, as necessary the Utilities can file for a change to their BTER rates to more closely match actual prices. The Utilities remain committed to maintaining a positive relationship with our regulators for the benefit of all stakeholders.

Significant Business Issues

While SPR and the Utilities have addressed many issues that were facing us in past years, we continue to face a number of key business issues, including, among other things: the ongoing litigation involving Enron, improving our debt profile, managing of our energy risk, and pursuing strategic initiatives to reduce our reliance on external power supplies. 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

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.

exclusive jurisdiction over the determination of whether any such payments are unjust, unreasonable or contrary to the public interest.

Improved Debt Profile

In 2005, management has sought and continues 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.

In May 2005, SPR completed a tender offer to exchange $99,142,000 of its existing Premium Income Equity Securities (“Old PIES”) for new Premium Income Equity Securities (“New PIES”). The amount exchanged equaled approximately 41% of the Old PIES securities. The senior notes associated with the New PIES were remarketed on June 14, 2005 at a rate of 7.803%, reduced from the 7.93% rate of the senior notes associated with the Old PIES. The remarketed Senior Notes will mature on June 15, 2012.

On June 20, 2005, SPR issued and sold $140,860,000 of its Series A Floating Rate Senior Notes, due November 16, 2005, and $99,140,000 of its Series B Floating Rate Senior Notes, due November 16, 2005 (collectively, the “Floating Rate Notes”). $230,500,000 of the proceeds from this offering were used to make an equity contribution to NPC as detailed in Note 4, Short-Term Borrowings of the Condensed Notes to Financial Statements. In a continuing effort to improve NPC’s debt profile, on July 14, 2005 upon receipt of the equity contribution from SPR, discussed above, NPC redeemed $87,500,000 aggregate principal amount of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, and $122,500,000 aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013, in accordance with the redemption provisions of these securities. These redemptions constituted 35% of the principal amounts outstanding of each of the Series E and Series G Notes.

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of its $300 million outstanding 7.25% Notes due 2010 (7.25% Notes) to convert their 7.25% Notes to shares of SPR common stock. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” an approximate $54 million cash payment was expensed during the third quarter of 2005 which SPR paid using a portion of the proceeds from the $225 million private placement of 6.75% Notes due 2017. SPR issued approximately 65.7 million shares of common stock in connection with this conversion.

On August 12, 2005, SPR conducted a private placement of $225 million 6.75% Senior Notes, due 2017. The proceeds were used to repurchase approximately $141 million 7.93% Senior Notes associated with the Old PIES, pay approximately $54 million in premiums associated with the conversion of our 7.25% Notes and fund the associated fees and expenses in connection with the conversion offer, and provide additional liquidity to SPR. On August 10, 2005, the remaining $141,076,000 aggregate principal amount of SPR’s 7.93% senior notes associated with the Old PIES were remarketed and SPR entered into an agreement to purchase all of the remarketed Notes. On August 15, 2005, following the settlement of the remarketing, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (described above) to purchase all of the 7.93% senior notes in the remarketing.

Details of the PIES transaction are discussed later under SPR Liquidity and Capital Resources.

These transactions are among those that are being executed in order to lead the companies toward achieving investment credit ratings to the Utilities’ secured debt.

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 have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. The Utilities’ significant need to tap energy markets is necessary because the Utilities’ ownership and contractual call on power generating assets is insufficient to meet our customers’ energy needs. 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 economic 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 were forecast during the PUCN’s approval process. 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 contractual completion dates in the Fluor contract are December 2005 for Unit 1 and March 2006 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.

NPC announced on June 21, 2005 that it has signed an agreement to acquire from Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy Corporation (“PWEC”), a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC (“GenWest”), a 75 percent ownership interest in the Silverhawk Power Plant (“Silverhawk”). Silverhawk is a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles northeast of Las Vegas. The purchase price of Silverhawk is approximately $208 million, subject to certain closing adjustments. The PUCN approved the acquisition of the Silverhawk plant, however, further approval is required from the FERC and the Federal Trade Commission through a Hart-Scott-Rodino filing. NPC currently plans to fund the closing of the acquisition of Silverhawk utilizing debt.

On August 1, 2005, SPPC filed an amendment to its IRP previously approved by the PUCN on November 18, 2004. In the amendment SPPC is requesting approval to construct a 514 MW combined cycle unit at its Tracy Station. The estimated cost to construct the unit is $421 million and is scheduled to be in service by June 2008. The unit will provide needed generation within the Utilities’ control area to reliably serve the growing needs of Northern Nevada. SPPC is expecting a decision late in the fourth quarter of 2005.

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 Impacts

Federal

In August 2005, President Bush signed the Energy Bill into law. The Energy Bill is comprehensive legislation that will substantially affect the regulation of energy companies. The Act amends federal energy laws and provides the FERC with new oversight responsibilities. Among the important potential changes for SPR as a result of this legislation are the following:

	•		The Energy Bill repeals the Public Utility Holding Company Act of 1935 (PUHCA) and, among other things, grants FERC and state utility commissions access to the books and records of holding company systems, provides for FERC review of allocations of costs of non-power goods and administrative services, and modifies the jurisdiction of FERC over certain mergers and acquisitions involving public utilities or holding companies.

	•		Federal support will be available for certain clean coal power initiatives and renewable energy technologies.

	•		The FERC will appoint and oversee an electric reliability organization to establish and enforce mandatory reliability rules regarding the interstate electric transmission system.

	•		The FERC will establish incentives for transmission companies, such as performance-based rates, recovery of the costs to comply with reliability rules, and accelerated depreciation for investments in transmission.

	•		The FERC will be given exclusive jurisdiction over the Enron termination payment claims (Cantwell Amendment).

Nevada 2005 Legislature

The 2005 Nevada Legislative Session and 22^nd Special Session ended on June 7, 2005. The Legislature passed several bills that will affect the Utilities.

Senate Bill 238 requires a natural gas utility to request approval from the PUCN to adjust its rates on a quarterly basis between annual rate adjustment applications based on changes in the costs of natural gas.

Senate Bill 256 establishes a specific schedule for electric utilities to file general and deferred rate applications. SPPC is to file a general rate case on or before October 3, 2005, and at least once every 24 months thereafter. NPC is to file a general rate case on or before November 15, 2006, and at least once every 24 months thereafter. In addition, the filing dates for the annual deferred rate cases have been changed to December 1, 2005 for SPPC and January 17, 2006 for NPC. This bill also allows the PUCN 210 days to render a decision on rate cases.

Assembly Bill 3 (AB 3) revises the provisions governing the portfolio standard for renewable energy and energy from a qualified energy recovery process. The portfolio standard requires each provider to generate, acquire or save electricity from portfolio energy systems or efficiency measures in an amount that is not less than 20% by calendar year 2015, which represents an increase from 15% under the current standard. Additionally, AB 3 allows a provider of electric service to receive one portfolio energy credit for each kilowatt-hour of electricity that the provider generates, acquires or saves from a portfolio energy system or efficiency measure.

SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Consolidated)

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later. SPR’s operating results on a stand alone basis included approximately $64.4 million and $86.3 million of interest costs for the nine months ended September 30, 2005 and 2004, respectively.

During the three months ended September 30, 2005, SPR had earnings applicable to common stock of approximately $61 million compared to approximately $90.6 million earnings applicable to common stock for the same period in 2004. The decrease in SPR’s earnings applicable to common stock for the three months ended September 30, 2005 compared to the same period in 2004 was primarily due to a charge of approximately $35 million (after taxes) during the third quarter of 2005 of costs associated with the early conversion of the convertible notes (discussed in Financing Transactions below).

During the nine months ended September 30, 2005, SPR had earnings applicable to common stock of approximately $60.6 million compared to an approximately $1.3 million in earnings applicable to common stock for the same period in 2004. The increase in SPR’s earnings applicable to common stock during the nine months ended September 30, 2005 compared to the same period in 2004 was primarily due to the following charges recorded during the nine months ended September 30, 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;

	•		a charge of approximately $23.7 million of tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8³/4% Senior Unsecured Notes due 2005; and

	•		a charge of approximately $47 million as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Pinon Pine.

The increase in earnings applicable to common stock due to the above charges were partially offset by the $35 million charge (after taxes) during the third quarter of 2005 for costs associated with the early conversion of the convertible notes (discussed in SPR Financing Transactions).

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

As of November 2, 2005, NPC had paid $27.1 million in dividends to SPR and declared an additional dividend of approximately $8.5 million. As of November 2, 2005, SPPC paid $19.8 million in dividends to SPR and declared an additional dividend of $4.3 million to SPR. As of November 2, 2005, SPPC paid approximately $2.9 million in dividends and declared an additional $1.95 million in dividends to holders of its preferred stock.

ANALYSIS OF CASH FLOWS

SPR’s consolidated net cash flows decreased for the nine months ended September 30, 2005 compared to the same period in 2004, primarily as a result of an increase in cash used in investing activities offset by increases in cash from operating and financing activities. Cash flows for operating activities are higher in 2005 due to 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 was the $60 million escrow payment for Enron in 2004, and a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facilities. Partially offsetting these increases were energy costs that were higher than amounts being collected in rates. The increase in cash used by investing activities was mainly due to construction at NPC for the Chuck Lenzie project. The increase in cash from financing activities in 2005, when compared to 2004, was primarily due to the issuance of short term borrowings of $240 million at SPR and the $50 million draw on NPC’s revolving credit facility in 2005, and the repayment of $25 million in short-term borrowings in March 2004. In the third quarter of 2005 SPR issued $225 million of long term debt and converted $248 million of 7.25% Convertible Notes into 65.7 million common shares.

LIQUIDITY AND CAPITAL RESOURCES

SPR, on a stand-alone basis, had cash and cash equivalents of approximately $33.5 million at September 30, 2005.

SPR expects to repay its short-term floating rate senior notes on November 16, 2005 with the $240 million of proceeds it will receive on November 15, 2005 from the settlement of the common stock purchase contracts associated with its Old PIES and New PIES. Given the current balance of 4,804,350 PIES outstanding, approximately 17,344,183 SPR common shares are expected to be issued at the settlement date of November 15, 2005, based on the 20-day average closing price as of November 2, 2005.

SPR paid approximately $49.1 million of debt service obligations on its existing debt securities during the nine months ended September 30, 2005. SPR has approximately $12.8 million payable of debt service obligations remaining during 2005, which SPR expects to meet through the payment of dividends by the Utilities to SPR. As noted below, to induce the holders of its 7.25% Notes to convert their notes early, SPR paid a $54 million cash payment.

In the nine months ended September 30, 2005, SPR entered into certain financing transactions discussed below. There were no other material changes to contractual obligations as set forth in SPR’s 2004 10-K during the three months and nine months ended September 30, 2005.

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 September 30, 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 are permitted to 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 are permitted to 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 or under their PUCN dividend restriction. As of November 2, 2005, NPC paid $27.1 million in dividends to SPR and declared an additional dividend of approximately $8.5 million. As of November 2, 2005, SPPC paid dividends of $19.8 million to SPR and declared an additional dividend of $4.3 million. As of November 2, 2005, SPPC paid approximately $2.9 million in dividends and declared an additional $1.95 million in dividends to holders of its preferred stock.

Financing Transactions (SPR — Holding Company)

PIES Transactions

On April 15, 2005, SPR commenced an offer to exchange its Old PIES for new New PIES plus an exchange fee of $0.125 in cash for each Old PIES tendered. On May 24, 2005, the tender offer was completed with 1,982,822 or about 41% of the 4,804,350 Old PIES outstanding tendered for exchange. The remaining 2,821,528 Old PIES remained outstanding. The New PIES are similar to the Old PIES except that the New PIES (i) allow for 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.

On August 10, 2005, the remaining $141,076,000 aggregate principal amount of its 7.93% Senior Notes associated with the Old PIES were remarketed. On August 15, 2005, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (described below under the headingPrivate Placement) to purchase all of the 7.93% Senior Notes that were remarketed. As with the May 2005 remarketing of the 7.93% Senior Notes, the proceeds of this remarketing were used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities will serve as substitute collateral for the senior notes component of the Old PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S treasury securities upon maturity will be used to provide the consideration necessary to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the Old PIES through November 15, 2005.

Floating Rate Notes

Convertible Notes

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of its $300 million outstanding 7.25% Convertible Notes due 2010 (7.25% Notes) to convert their 7.25% Notes to shares of SPR common stock. The conversion offer, which was extended to September 2, 2005, was accepted by 100% of the holders of the 7.25% Notes. Under the terms of the offer, for each $1,000 in liquidation amount of 7.25% Notes tendered, holders received the conversion consideration and 219.1637 shares of common stock. The consideration offered was an amount paid in cash equal to $180 per $1,000 principal amount of 7.25% Notes validly surrendered for conversion plus an amount equivalent to the interest that would have accrued thereon from and after August 14, 2005 (which was the last interest payment date on the 7.25% Notes prior to the expiration of the offer). On September 8, 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were issued to the holders in exchange for the 7.25% Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” the $54 million cash payment was expensed during the third quarter of 2005.

Private Placement

Limits on Restricted Payments

Each of SPR’s Floating Rate Notes, its remarketed 7.803% Senior Notes due 2012, its 8 5/8% Senior Notes due 2014 and its 6.75% Senior Notes due 2017 limit SPR’s ability to make certain payments (including dividends on common stock, payments on subordinated indebtedness, certain investments and other payments in respect of any equity interests of SPR); provided, however, that SPR may make such payments if:

	•		there are no defaults or events of default with respect to the Floating Rate Notes or the senior notes, as applicable,

	•		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 2.0 to 1, and

	•		the total amount of such payments is less than:

	•		the sum of 50% of SPR’s consolidated net income measured on a quarterly basis cumulative of all quarters from April 1, 2004, plus

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

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

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

The terms of SPR’s Floating Rate Notes, its remarketed 7.803% Senior Notes due 2012, its 8 5/8% Senior Notes due 2014 and its 6.75% Senior Notes due 2017 also permit SPR to make payments in excess of the amounts described above in an aggregate amount not to exceed $50 million from the date of the issuance of the applicable series of senior notes.

In addition, the terms of SPR’s Floating Rate Notes, its remarketed 7.803% Senior Notes due 2012 and its 6.75% Senior Notes due 2017 restrict SPR and its restricted subsidiaries from incurring any additional indebtedness unless:

	•		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 2.0 to 1, or

	•		the debt incurred is specifically permitted under the terms of the applicable series of senior notes, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, certain letters of credit issued to support SPR’s obligations with respect to energy suppliers, indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan, as amended, or Sierra Pacific Power Company’s 2004 Integrated Resource Plan, as amended, and additional indebtedness not to exceed $75 million at any time outstanding.

Among other things, SPR’s Floating Rate Notes, its remarketed 7.803% Senior Notes due 2012 and its 6.75% Senior Notes due 2017 also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. There are also limitations on certain fundamental structural changes to SPR and limitations on the disposition of property. In the event of a change of control of SPR, the holders of the applicable series of senior notes and the remarketed new PIES senior notes are entitled to require that SPR repurchase their applicable senior notes for a cash payment equal to 100% of the aggregate principal amount plus accrued and unpaid interest.

If SPR’s Floating Rate Notes, its remarketed 7.803% Senior Notes due 2012 and its 6.75% Senior Notes due 2017 are upgraded to investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Rating Group, Inc., certain restrictions applicable to such notes, including the covenants related to restricted payments, the incurrence of indebtedness and issuance of preferred stock, dividend and other payment restrictions affecting restricted subsidiaries, the designation of restricted and unrestricted subsidiaries, transactions with affiliates and restrictions on business activities, will be suspended and will no longer be in effect so long as such notes remain investment grade.

Additional covenants applicable to SPR’s Floating Rate Notes, its remarketed 7.803% Senior Notes due 2012 and its 6.75% Senior Notes due 2017 are discussed below.

Capital Structure (SPR Consolidated)

SPR’s actual capital structure on a consolidated basis was as follows at (dollars in thousands):


	September 30, 2005				December 31, 2004
Short-Term Debt⁽¹⁾	$	278,804	4.7	%	$	8,491	0.1	%
Long-Term Debt		3,734,822	63.6	%		4,081,281	72.4	%
Preferred Stock		50,000	0.9	%		50,000	0.9	%
Common Equity		1,807,408	30.8	%		1,498,616	26.6	%

Total	$	5,871,034	100	%	$	5,638,388	100	%


(1)		Includes current maturities of long-term debt.

Limitations on Indebtedness

The terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due 2014, its $99.1 million 7.803% Senior Notes due 2012, its Floating Rate Notes and its 6.75% Senior Notes due 2017 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 applicable series of notes, which permit 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 applicable series of notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of notes remain investment grade. As of September 30, 2005, SPR, NPC and SPPC would have been able to issue approximately $546 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.75%, 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).”

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 Utilities’ judgment default provisions as described in the 2004 10-K. The terms of SPR’s senior notes including its 8 5/8% Senior Unsecured Notes due 2014, short-term floating rate senior notes and remarketed new PIES senior notes provide for a default in the event that SPR or either of the Utilities fails to pay a final judgment in excess of $10 million or more for a period of 60 days.

Effect of Holding Company Structure

As of September 30, 2005, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $99 million of its unsecured 7.803% Senior Notes due 2012; $240 million of short-term floating rate Senior Notes, due November 16, 2005; $225 million of 6.75% Senior Notes due 2017 and $335 million of its unsecured 8 5/8% Senior Notes due 2014. (See Financing Transactions)

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

As of September 30, 2005, SPR, NPC, SPPC, and their subsidiaries had approximately$4.0 billion of debt and other obligations outstanding, consisting of approximately $2.1 billion of debt at NPC, approximately $1.0 billion of debt at SPPC and approximately $900 million 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 September 30, 2005, NPC recognized net income of approximately $99.5 million compared to $86.2 million for the same period in 2004. During the nine months ended September 30, 2005, NPC recognized net income of approximately $112.4 million compared to net income of approximately $84.4 million for the same period in 2004. As of November 2, 2005, NPC paid a common stock dividend of $27.1 million to SPR and declared an additional dividend of approximately $8.5 million on November 2, 2005.

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

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


	Three Months								Nine Months
	Ended September 30,								Ended September 30,
						Change from								Change from
	2005			2004		Prior Year %			2005			2004		Prior Year %
Operating Revenues:
Electric	$	675,181		$	633,609		6.6	%	$	1,480,699		$	1,410,067		5.0	%

Energy Costs:
Purchased power		393,414			300,290		31.0	%		763,096			619,329		23.2	%
Fuel for power generation		86,282			67,216		28.4	%		195,134			176,883		10.3	%
Deferral of energy costs-disallowed		—			—					—			1,586		N/A
Deferral of energy costs-electric-net		(76,899	)		9,496		N/A			(32,965	)		91,622		N/A

		402,797			377,002		6.8	%		925,265			889,420		4.0	%


Gross Margin
Electric	$	272,384		$	256,607		6.1	%	$	555,434		$	520,647		6.7	%

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

Electric Operating Revenues


	Three Months							Nine Months
	Ended September 30,				Change from			Ended September 30,				Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Residential	$	332,621	$	301,651		10.2	%	$	668,927	$	620,782		7.8	%
Commercial		117,709		110,501		6.5	%		298,954		283,566		5.4	%
Industrial		195,355		184,901		5.7	%		435,979		415,228		5.0	%

Retail revenues		645,685		597,053		8.1	%		1,403,860		1,319,576		6.4	%
Other⁽¹⁾		29,496		36,556		-19.3	%		76,839		90,491		-15.1	%

Total Revenues	$	675,181	$	633,609		6.6	%	$	1,480,699	$	1,410,067		5.0	%


Retail sales in thousands of megawatt-hours (MWH)		6,684		6,155		8.5	%		15,286		14,644		4.4	%

Average retail revenue per MWH	$	96.60	$	97.00		-0.4	%	$	91.84	$	90.11		1.9	%


¹		Primarily wholesale, as discussed below.

NPC’s retail revenues were higher for the three months ended September 30, 2005, as compared to the same period in the prior year due to customer growth and hotter summer weather. The number of residential, commercial, and industrial customers increased by 5.5%, 6.2%, and 4.6%, respectively. During the month of July 2005, NPC experienced five days of peak system usage due to hotter weather temperatures. These increases were slightly offset by an energy rate decrease of .6% overall which resulted from NPC’s Deferred Energy Rate Case effective April 1, 2005 (refer to Regulatory Proceedings).

Retail revenues were higher for the nine months ended September 30, 2005, as compared to the same period in 2004, due to customer growth and higher rates. The number of residential, commercial, and industrial customers increased by 5.6%, 5.9%, and 3.7%, respectively. Higher rates 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). These increases were slightly offset by an overall decrease of .6% resulting from NPC’s Deferred Energy Rate Case effective April 1, 2005.

Based on NPC’s projected customer forecast, NPC expects the number of retail electric customers in the Clark County area to continue to grow. Effective October 1, 2005, NPC’s energy rates increased as a result of NPC’s Base Tariff Energy Rate update filing. (Refer to Regulatory Proceedings).

Electric Operating Revenues — Other decreased for the three months and nine months ended September 30, 2005 compared to the same periods in 2004, primarily due to a decrease in sales volumes for wholesale electric power to other utilities and certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power. Partially offsetting this decrease was a refund in 2004 of $5.9 million owed to transmission customers as a result of FERC’s approval of a tariff agreement on July 8, 2004 (refer to Regulatory Proceedings in the 2004 10-K), which decreased revenues in 2004. The tariff agreement also lowered the transmission rates which contributed to the decrease in 2005 revenues.

Purchased Power


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Purchased Power:	$	393,414	$	300,290		31.0	%	$	763,096	$	619,329		23.2	%

Purchased Power in thousand of MWhs		4,834		4,561		6.0	%		10,403		10,059		3.4	%
Average cost per MWh of Purchased Power	$	81.38	$	65.84		23.6	%	$	73.35	$	61.57		19.1	%

NPC’s purchased power costs increased for the three months ended September 30, 2005, compared to the same period in 2004, due to higher prices and increased volume. NPC’s energy contracts calculate prices using gas indexes. Therefore, higher natural gas prices in 2005 increased the price of purchased power. During July 2005, NPC experienced high peak demand that contributed to the increased volume for the three months ended September 30, 2005.

NPC’s purchased power costs increased for the nine months ended September 30, 2005, compared to the same period in 2004, primarily due to higher prices and volumes as discussed above. Furthermore, purchased power costs were higher due to gas tolling agreements entered into during the second quarter of 2004 and June 1, 2005. These gas tolling agreements are purchased power agreements where NPC provides natural gas to the supplier who generates the energy for NPC. The gas tolling agreements are based on gas indexes; therefore, the increase in natural gas prices increased the cost of purchased power.

Fuel For Power Generation


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Fuel for Power Generation	$	86,282	$	67,216		28.4	%	$	195,134	$	176,883		10.3	%

Thousands of MWhs generated		2,286		2,362		-3.2	%		6,021		6,295		-4.4	%
Average cost per MWh of Generated Power	$	37.74	$	28.46		32.6	%	$	32.41	$	28.10		15.3	%

Fuel for generation costs for the three and nine months ended September 30, 2005 increased compared to the same periods in the prior year due to higher natural gas prices. The decrease in volume of generation for the same periods was due to NPC satisfying more of its native load requirements through purchase power rather than generation.

Deferred Energy Costs


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
						Change from							Change from
	2005			2004		Prior Year %		2005			2004		Prior Year %
Deferred energy costs disallowed	$	—		$	—		N/A	$	—		$	1,586		N/A
Deferred energy costs — net	$	(76,899	)	$	9,496		N/A	$	(32,965	)	$	91,622		N/A

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

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

Deferral of energy costs — net decreased for the three months and nine months ended September 30, 2005 compared to the same periods in 2004 due to fuel and purchased power costs exceeding revenues to a greater extent in 2005 than in 2004. Contributing also to the decrease was a decrease in amortization as a result of lower unamortized deferred energy balances and amortization rates in 2005 as compared to 2004.

See “Critical Accounting Polices” 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						Nine Months
	Ended September 30,						Ended September 30,
					Change						Change
					from Prior						from Prior
	2005		2004		Year %		2005		2004		Year %
Allowance for other funds used during construction	$	5,119	$	487		N/A	$	13,017	$	1,769		N/A

Allowance for borrowed funds used during construction	$	6,362	$	759		N/A	$	16,154	$	2,465		N/A

	$	11,481	$	1,246		N/A	$	29,171	$	4,234		N/A

NPC’s AFUDC increased for the three and nine months ended September 30, 2005 compared to the same periods in 2004 due to an increase in Construction-Work-in-Progress (CWIP) associated with the October 2004 purchase of the partially completed Chuck Lenzie Generation Plant.

Other (Income) and Expenses


	Three Months									Nine Months
	Ended September 30,									Ended September 30,
							Change									Change
							from									from
							Prior									Prior
	2005			2004			Year %			2005			2004			Year %
Other operating expense	$	55,760		$	45,515			22.5	%	$	155,971		$	136,150			14.6	%
Maintenance expense	$	10,624		$	10,834			-1.9	%	$	43,976		$	47,580			-7.6	%
Depreciation and amortization	$	31,258		$	29,900			4.5	%	$	92,421		$	88,630			4.3	%
Income tax expense	$	42,092		$	43,346			-2.9	%	$	40,054		$	37,232			7.6	%
Interest charges on long-term debt	$	38,587		$	37,736			2.3	%	$	121,729		$	112,570			8.1	%
Interest charges-other	$	4,204		$	3,824			9.9	%	$	12,775		$	13,652			-6.4	%
Interest accrued on deferred energy	$	(5,557	)	$	(5,142	)		8.1	%	$	(14,298	)	$	(15,335	)		-6.8	%
Disallowed merger costs	$	—		$	—			N/A		$	—		$	3,961			N/A
Other income	$	(5,238	)	$	(5,335	)		-1.8	%	$	(17,600	)	$	(16,464	)		6.9	%
Other expense	$	1,608		$	1,698			-5.3	%	$	5,001		$	4,626			8.1	%
Income taxes — other income and expense	$	4,578		$	3,109			47.2	%	$	12,625		$	8,154			54.8	%

Other operating expense increased for the three and nine month periods ended September 30, 2005 compared to the same periods in 2004 primarily due to increased advisory fees, amortization of regulatory assets and severance costs associated with the reorganization of SPPC, NPC and SPR.

Maintenance expense for the three month period ended September 30, 2005 was comparable to the same period in the prior year. The decrease in Maintenance expense for the nine month period ending September 30, 2005 compared to the same

period in the prior year was due to the timing of scheduled and unscheduled plant maintenance at Clark Station, Reid Gardner and Navajo during 2004.

NPC’s depreciation and amortization expenses were higher for the three months and the nine months ended September 30, 2005 compared to the same periods in 2004 primarily as a result of increases to plant-in-service.

NPC’s income tax expense for the three and nine months ended September 30, 2005 was comparable to the same period in the prior year.

Interest charges on Long-Term Debt increased for the three months and nine months ended September 30, 2005 compared to the same period in 2004 due to higher debt balances during the three months and nine months ended September 30, 2005. See Note 7, Long-Term Debt of the Notes to Consolidated Financial Statements in the 2004 10-K and Note 5, Long-Term Debt for additional information regarding long-term debt.

Interest charges-other for the three months ended September 30, 2005 increased compared to the same period in 2004 due to costs associated with the debt redemption of $210 million (See Note 5, Long-Term Debt for additional information regarding long-term debt). These costs were offset by an interest adjustment related to the settlement of a terminated contract claim. Interest charges-other decreased for the nine months ended September 30, 2005 compared to the same period in 2004 due to a reduction in fees for short-term financing.

Interest accrued on deferred energy costs increased for the three months ended September 30, 2005 compared to the same period 2004 primarily due to higher deferred fuel and purchased power balances during the period. Interest accrued on deferred energy costs decreased for the nine months ended September 30, 2005 compared to the same period 2004 primarily due to lower deferred fuel and purchased power balances during 2005.

Disallowed merger costs for the nine months ended September 30, 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 for the three months ended September 30, 2005 were comparable to the same period in 2004. NPC’s Other income increased for the nine months ended September 30, 2005, compared to the same period in 2004 due to increased interest income from temporary investments.

NPC’s Other expense decreased for the three months ended September 30, 2005 compared to the same period in 2004, due to various charges, all of which were not individually significant. NPC’s Other expense for the nine months ended September 30, 2005 increased from the same period in 2004 due to higher lobbying activities and the reclassification of costs associated with NPC’s Supplementary Executive Retirement Plan. These increases were partially offset by a decrease in corporate advertising.

NPC’s income taxes-other income and expense for the three and nine month periods ending September 30, 2005 was comparable to the same period in the prior year.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during the nine months ended September 30, 2005, compared to the same period in 2004, primarily as a result of an increase in cash used for investing activities offset by an increase in cash flow from financing activities. Cash used in investing activities increased mainly due to an increase in utility construction for the Chuck Lenzie project under construction in 2005. Cash from financing activities increased in 2005 due to the draw of $50 million on the revolving credit facility and an equity contribution by SPR of $230 million, which enabled NPC to redeem $210 million of high yield notes in the third quarter.

LIQUIDITY AND CAPITAL RESOURCES

NPC had cash and cash equivalents of approximately $64.6 million at September 30, 2005 which does not include restricted cash of $49 million which has been deposited into escrow in connection with the stay of the Enron Judgment. As of November 4, 2005 NPC has additional liquidity in the amount of $500 million as discussed below in financing transactions. On July 15, 2005, SPR contributed $230.5 million in equity to NPC. NPC used this equity contribution to redeem $210 million

of General and Refunding Mortgage Notes. The remainder of the equity contribution was used to pay the call premiums and the fees and expenses related to the redemption.

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 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 revolving credit facility. As of September 30, 2005, NPC has incurred approximately $406.2 million in construction expenditures.

On June 21, 2005, Nevada Power Company entered into an agreement with GenWest LLC, a wholly owned subsidiary of Pinnacle West Capital Corporation, to acquire its 75% ownership of the Silverhawk Power Station. NPC filed a financing application with the PUCN to issue new debt in connection with the Silverhawk acquisition. On September 23, 2005, the PUCN issued an order giving NPC authority to issue up to $210 million of long-term debt securities for the purchase of the 75% interest in Silverhawk (See Regulatory Proceedings). There were no other material changes to contractual obligations as set forth in NPC’s 2004 10-K during the three months and nine months ended September 30, 2005.

Financing Transactions

Amended Credit Facility

On November 4, 2005 NPC amended and restated its existing secured $350 million revolving credit facility, maturing in October 2007, increasing the size of the facility to $500 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association; however, the total amount of the credit facility will be reduced by $150 million in November 2006 unless NPC obtains long-term PUCN authority for this amount prior to such date. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an alternate base rate or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s alternate base rate margin is 1.00% and its Eurodollar margin is 2.00%. As of November 4, 2005 NPC had $70.4 million of letters of credit under the revolving credit facility.

Collateral

The revolving credit facility is secured by NPC’s General and Refunding Mortgage Bonds; however, in the event that NPC obtains an unsecured debt rating from at least two rating agencies that is at least BBB- from S&P and Fitch or Baa3 from Moody’s, the General and Refunding Mortgage Bonds securing the revolving credit facility will be released.

Conditions to Borrowing

The credit agreement contains customary conditions to borrowing including requirements that no material litigation, defaults or other events that could have a material adverse effect on NPC’s business shall have occurred. In the event that NPC’s unsecured debt ratings meet the conditions discussed above, the requirement that no material adverse changes shall have occurred ceases to be a condition to borrowing under the credit agreement.

Financial Covenants

The 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.

Dividend Restriction

The credit agreement contains a dividend limitation similar to certain of NPC’s existing dividend limitations. The limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s Premium Income Equity Securities) provided that:

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

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

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

The credit agreement also permits NPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed $50 million from the date of the establishment of the credit agreement.

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

	•		there are no defaults or events of default with respect to the credit agreement,

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

	•		the total amount of such dividends is less than the sum of:

	•		50% of NPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of the establishment of the revolving credit facility, plus

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

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

The dividend restrictions described above shall not apply if (i) NPC obtains an unsecured debt rating on its general and refunding bonds securing the credit facility from at least two rating agencies that is at least BBB- from S&P and Fitch or Baa3 from Moody’s, in each case with a stable or better outlook, and (ii) there are no defaults or events of default with respect to the credit agreement.

Restriction on Additional Indebtedness

The credit agreement also restricts NPC from incurring any additional indebtedness unless:

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

	•		the debt incurred is specifically permitted under the terms of the credit agreement, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC’s obligations with respect to energy and gas suppliers, or indebtedness incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan.

Other Restrictions

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

Defaults

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

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

Redemption of Indebtedness

Mortgage Indentures

NPC’s Indenture of Mortgage, dated as of October 1, 1953, between NPC and Deutsche Bank Trust Company Americas (the “First Mortgage Indenture”), creates a first priority lien on substantially all of NPC’s properties. As of September 30, 2005, $372.5 million of NPC’s first mortgage bonds were outstanding. In connection with the issuance of its Series E, Series G, Series I and Series L Notes and Series H Bond, 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 September 30, 2005, $1.1 billion of NPC’s General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

	1.		70% of net utility property additions,

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

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

On the basis of (1), (2) and (3) above and on plant accounting records as of September 30, 2005 (which do not include additions to plant associated with the acquisition of the Lenzie Generating Station), NPC had the capacity to issue approximately $508 million of additional General and Refunding Mortgage securities.

Although NPC has substantial capacity to issue additional General and Refunding Mortgage securities on the basis of property additions and retired securities, the financial covenants contained in the Series E, Series G, 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 (except for as discussed above in Amended Credit Facility), NPC would have been able to issue additional indebtedness. NPC’s most restrictive limitation on indebtedness is within certain note indentures of SPR, including SPR’s $335 million 8 5/8% Senior Unsecured Notes due 2014, $99.1 million 7.803% Senior Notes due 2012, $140.9 million Series A Floating Rate Senior Notes due November 16, 2005 and $99.1 million Series B Floating Rate Senior Notes due November 16, 2005. As of September 30, 2005, SPR, NPC and SPPC are restricted to issuing no more than approximately $546 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.75% based upon SPR’s most recent debt issuance, unless the indebtedness being issued is specifically permitted under the terms of SPR’s 6.75% Senior Notes due 2017. 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 September 30, 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 (except for as discussed above in Amended Credit Facility).

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 (except for as discussed above in Amended Credit Facility).

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended September 30, 2005, SPPC recognized net income of approximately $21.9 million compared to net income of approximately $21.8 million for the same period in 2004. During the nine months ended September 30, 2005, SPPC recognized net income of approximately $38.9 million compared to a net loss of approximately $2.7 million for the same period in 2004. As of November 2, 2005, SPPC paid $19.8 million in dividends to SPR and declared an additional dividend of $4.3 million to SPR. As of November 2, 2005, SPPC paid approximately $2.9 million in dividends and declared an additional $1.95 million in dividends to holders of its preferred stock.

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 are (dollars in thousands):


	Three Months									Nine Months
	Ended September 30,									Ended September 30,
							Change								Change
							from								from
							Prior Year								Prior Year
	2005			2004			%			2005			2004		%
Operating Revenues:
Electric	$	268,109		$	253,615			5.7	%	$	712,318		$	657,881		8.3	%
Gas		15,574			16,387			-5.0	%		115,248			97,742		17.9	%

		283,683		$	270,002			5.1	%		827,566			755,623		9.5	%


Energy Costs:
Purchased Power		111,409			92,481			20.5	%		260,498			230,577		13.0	%
Fuel for Power generation		67,439			59,494			13.4	%		176,427			166,715		5.8	%
Deferral of energy costs-electric-net		(17,414	)		(3,269	)		N/A			(7,591	)		1,436		N/A
Gas purchased for resale		12,906			11,322			14.0	%		89,410			73,721		21.3	%
Deferral of energy costs-gas-net		(2,001	)		297			N/A			(997	)		266		N/A

		172,339			160,325			7.5	%		517,747			472,715		9.5	%

Energy Costs by Segment:
Electric		161,434			148,706			8.6	%		429,334			398,728		7.7	%
Gas		10,905			11,619			-6.1	%		88,413			73,987		19.5	%

		172,339			160,325			7.5	%		517,747			472,715		9.5	%


Gross Margin by Segment:
Electric	$	106,675		$	104,909			1.7	%	$	282,984		$	259,153		9.2	%
Gas	$	4,669		$	4,768			-2.1	%	$	26,835		$	23,755		13.0	%

	$	111,344		$	109,677			1.5	%	$	309,819		$	282,908		9.5	%

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

Electric Operating Revenues


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change							Change
					from							from
					Prior							Prior
	2005		2004		year %			2005		2004		year %
Electric Operating Revenues:
Residential	$	78,271	$	69,367		12.8	%	$	210,403	$	182,003		15.6	%
Commercial		93,491		85,808		8.9	%		241,758		220,717		9.5	%
Industrial		89,909		82,407		9.1	%		240,547		219,531		9.6	%

Retail revenues		261,671		237,582		10.1	%		692,708		622,251		11.3	%
Other⁽¹⁾		6,438		16,033		-59.8	%		19,610		35,630		-44.9	%

Total Revenues	$	268,109	$	253,615		5.7	%	$	712,318	$	657,881		8.3	%


Retail sales in thousands of MWh		2,543		2,438		4.3	%		7,015		6,843		2.5	%

Average retail revenue per MWh	$	102.90	$	97.45		5.6	%	$	98.75	$	90.93		8.6	%


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

SPPC’s retail revenues increased for the three months and nine months ended September 30, 2005 as compared to the same periods in the prior year due to increased rates, increased customer usage and customer growth. Nevada customer rates increased as a result of SPPC’s General Rate Case, effective June 1, 2004, an increase in Nevada customer energy rates as a result of SPPC’s Deferred Energy Cases effective July 15, 2004 and June 1, 2005 and increased California customer rates effective December 1, 2004 and September 1, 2005. Customer usage increased during the third quarter due to higher temperatures. Also contributing to the increase during 2005 was growth in residential and commercial customers (3.1%, and 3.2% for the nine months ended September 30, 2005, respectively).

The decrease in Electric Operating Revenues-Other for the three and nine months ended September 30, 2005, compared to the same periods in 2004, was primarily due to the decrease in sales volume of wholesale electric power to other utilities. Also contributing to the decrease was certain types of transactions that were reported in revenues for 2004 which are now being netted in purchase power.

On October 27, 2005 the PUCN voted to increase the electric BTER % effective November 1, 2005. (Refer to Regulatory Proceedings).

In February 2004, Barrick Gold (Barrick), a large SPPC mining customer, filed an AB 661 application indicating its intention to construct a 118 MW generating facility to meet a majority of its electric power needs. Barrick indicates it intends to continue to purchase transmission and distribution services from SPPC and sell approximately 8 MW of capacity from this new facility to SPPC. When Barrick’s new generating facility becomes operational in December 2005, this customer will reduce kilowatt-hour retail consumption on SPPC‘s electric system by approximately 11% and, in turn, SPPC will reduce its power purchases.

Gas Operating Revenues


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change							Change
					from Prior							from Prior
	2005		2004		year %			2005		2004		year %
Gas Operating Revenues:
Residential	$	7,110	$	7,054		0.8	%	$	61,204	$	49,132		24.6	%
Commercial		3,850		3,950		-2.5	%		30,327		25,470		19.1	%
Industrial		1,999		1,691		18.2	%		11,121		7,959		39.7	%

Retail revenue		12,959		12,695		2.1	%		102,652		82,561		24.3	%
Wholesale revenue		1,939		3,048		-36.3	%		10,547		13,049		-19.2	%
Miscellaneous		676		644		5.0	%		2,049		2,132		-3.9	%

Total Revenues	$	15,574	$	16,387		-4.9	%	$	115,248	$	97,742		17.9	%


Retail sales in thousands of decatherms		1,163		1,227		-5.2	%		10,315		8,714		18.4	%

Average retail revenues per decatherm	$	11.14	$	10.35		7.6	%	$	9.95	$	9.47		5.1	%

Retail gas revenues increased for the three months ended September 30, 2005 as compared to the same period in 2004 primarily due to increased rates and customer growth. Nevada customer rates increased as a result of SPPC’s Purchased Gas Adjustment filings which became effective November 1, 2004 and August 1, 2005 (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 was the growth in residential, commercial and industrial customers of 4.4%, 4.2% and 16.3%, respectively.

Retail gas revenues increased for the nine months ended September 30, 2005 compared to the same period in 2004 primarily due to an increase in customer usage resulting from colder winter temperatures in the first months of 2005 as well as the increase in energy related rates as discussed above. Additionally, this increase was due to the growth in residential, commercial and industrial customers of 4.4%, 3.6% and 16.5%, respectively.

The decrease in the wholesale revenues for the three and nine months ended September 30, 2005 compared to the same period in 2004, was attributable to less excess gas available for sale and increased retail customer usage due to colder winter weather, respectively, contributing to a decrease in the year-to-date resale opportunities.

Purchased Power


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change							Change
	��				from							from
					Prior Year							Prior Year
	2005		2004		%			2005		2004		%
Purchased Power	$	111,409	$	92,481		20.5	%	$	260,498	$	230,577		13.0	%

Purchased Power in thousands of MWhs		1,329		1,622		-18.1	%		4,161		4,258		-2.3	%

Average cost per MWh of Purchased Power	$	83.83	$	57.02		47.0	%	$	62.60	$	54.15		15.6	%

Purchased power costs were higher for the three months and nine months ended September 30, 2005, compared to the same periods in 2004, primarily due to higher prices. Purchased power volume decreased for the three months and nine months ended September 30, 2005 compared to the same period in 2004 due to a decrease in purchases associated with risk management activities in 2005, which are included in purchased power.

Due to the continued increases in the cost of energy, SPPC anticipates an increase in the cost of purchase power during the fourth quarter of 2005.

Fuel For Power Generation


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change							Change
					from							from
					Prior Year							Prior Year
	2005		2004		%			2005		2004		%
Fuel for Power Generation	$	67,439	$	59,494		13.4	%	$	176,427	$	166,715		5.8	%

Thousands of MWh generated		1,221		1,249		-2.2	%		3,310		3,492		-5.2	%
Average fuel cost per MWh of Generated Power	$	55.23	$	47.63		16.0	%	$	53.30	$	47.74		11.6	%

Fuel for power generation costs increased for the three months ended September 30, 2005, compared to the same period in 2004 primarily due to higher natural gas prices. For the nine months ended September 30, 2005 fuel for power generation costs increased as compared to the same period in 2004 due to higher natural gas and coal prices. The decrease in volume of generation for this period was due to SPPC relying more on purchased power to satisfy its native load requirements.

Gas Purchased for Resale


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2005		2004		Prior Year %			2005		2004		Prior Year %
Gas Purchased for Resale	$	12,906	$	11,322		14.0	%	$	89,410	$	73,721		21.3	%

Gas Purchased for Resale (in thousands of decatherms)		1,487		2,025		-26.5	%		11,874		11,234		5.7	%

Average cost per decatherm	$	8.68	$	5.59		55.3	%	$	7.53	$	6.56		14.8	%

The cost of gas purchased for resale increased for the three months ended September 30, 2005, compared to the same period in 2004, primarily due to higher natural gas prices. The volume of gas purchased for resale decreased for the three months ended September 30, 2005, in relation to the same period in 2004 due to fuel forecasts more closely matching usage, leaving less fuel available for wholesale sales. For the nine months ended September 30, 2005 as compared to the same period in 2004 the cost of gas purchased for resale increased primarily due to the increase in natural gas prices and the volume of gas purchased for resale. The volume of gas purchased for resale increased for the nine months ended September 30, 2005 as compared to the same period in 2004 in relation to the colder winter weather January 2005 through May 2005.

Deferred Energy Costs


	Three Months								Nine Months
	Ended September 30,								Ended September 30,
							Change							Change
							from Prior							from Prior
	2005			2004			Year %		2005			2004		Year %
Deferred energy costs — electric - - net	$	(17,414	)	$	(3,269	)		N/A	$	(7,591	)	$	1,436		N/A
Deferred energy costs — gas — net		(2,001	)		297			N/A		(997	)		266		N/A

Total	$	(19,415	)	$	(2,972	)			$	(8,588	)	$	1,702

Deferred energy costs — electric and gas — represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than

amounts recoverable through rates the difference is recognized as an increase in costs. Deferred energy costs — net also include the current amortization of fuel and purchased power costs previously deferred.

Deferred energy costs — electric — net decreased for the three and nine months ended September 30, 2005, compared to the same periods in 2004, because fuel and purchased power costs exceeded the amounts recovered through rates to a greater extent during 2005 compared to the same period in 2004. The decrease in deferred energy costs for both periods in 2005 was partially offset by an increase in the amortization of prior deferred energy costs through current rates in 2005 compared to 2004.

Deferred energy costs — gas — net decreased for the three months ended September 30, 2005, due to natural gas costs exceeding the recovery of those costs through current rates during 2005 compared to the same period in 2004. Deferred energy costs — gas — net decreased for the nine months ended September 30, 2005, due to a decrease in amortization of prior deferred gas costs due to lower rates during 2005 compared to 2004. This decrease was partially offset by an increase in the recovery of natural gas costs through rates during 2005 compared to the same period in 2004.

Allowance For Funds Used During Construction (AFUDC)


	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change							Change
					from Prior							from Prior
	2005		2004		Year %			2005		2004		Year %
Allowance for other funds used during construction	$	429	$	230		86.5	%	$	1,229	$	1,513		-18.8	%

Allowance for borrowed funds used during construction	$	390	$	364		7.1	%	$	1,129	$	2,498		-54.8	%

	$	819	$	594		37.9	%	$	2,358	$	4,011		-41.2	%

SPPC’s AFUDC increased during the three months ended September 30, 2005, compared to the same period in 2004 due to an increase in CWIP primarily associated with the Ft. Churchill to Buckeye transmission line placed in service in September 2005. AFUDC decreased for the nine months ended September 30, 2005 compared to the same period in 2004 due to the completion of the Falcon to Gonder transmission line, which was placed in service in May 2004.

Other (Income) and Expenses


	Three Months									Nine Months
	Ended September 30,									Ended September 30,
							Change									Change
							from									from
							Prior									Prior
	2005			2004			Year %			2005			2004			Year %
Other operating expense	$	29,334		$	29,899			-1.9	%	$	97,872		$	93,601			4.6	%
Maintenance expense	$	6,313		$	5,212			21.1	%	$	20,064		$	15,570			28.9	%
Depreciation and amortization	$	22,610		$	21,530			5.0	%	$	67,534		$	64,866			4.1	%
Income tax expense	$	10,186		$	9,424			8.1	%	$	19,540		$	9,729			N/A
Interest charges on long-term debt	$	17,307		$	17,307			N/A		$	51,933		$	54,022			-3.9	%
Interest charges-other	$	1,001		$	928			7.9	%	$	3,402		$	5,555			-38.8	%
Interest accrued on deferred energy	$	(1,785	)	$	(1,635	)		9.2	%	$	(5,061	)	$	(3,972	)		27.4	%
Other income	$	(1,681	)	$	(765	)		N/A		$	(4,148	)	$	(2,521	)		64.5	%
Disallowed merger costs	$	—		$	—			N/A		$	—		$	1,929			N/A
Plant costs disallowed	$	—		$	—			N/A		$	—		$	47,092			N/A
Other expense	$	1,476		$	1,568			-5.9	%	$	4,709		$	4,123			14.2	%
Income taxes — other income and expense	$	782		$	458			70.7	%	$	1,997		$	(14,900	)		N/A

Other operating expense for the three month period ended September 30, 2005 was comparable to the same period in the prior year. Other operating expense increased for the nine month period ended September 30, 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 SPPC, NPC and SPR.

Maintenance expense for the three and nine month periods ended September 30, 2005 increased from the prior year due to the timing of scheduled and unscheduled plant maintenance at Valmy.

SPPC’s depreciation and amortization expenses were higher for the three and nine months ended September 30, 2005 compared to the same periods 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 in May 2004.

SPPC’s income tax expense for the three and nine months ended September 30, 2005, increased compared to the same periods during 2004, substantially as a result of an increase in pretax income.

SPPC’s interest charges on long-term debt for the three months ended September 30, 2005 were comparable to the same period in 2004. SPPC’s interest charges on long-term debt for the nine months ended September 30, 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 and Note 5, Long-Term Debt for additional information regarding long-term debt.

SPPC’s interest charges-other for the three months ended September 30, 2005 were comparable to the same period in 2004. SPPC’s interest charges-other for the nine months ended September 30, 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 and nine months ended September 30, 2005 compared to the same period in 2004 due to higher deferred fuel and purchased power balances and rates during 2005.

SPPC’s Other income for the three months and nine months ended September 30, 2005 increased primarily due to increased interest income.

Disallowed merger costs for the nine months ended September 30, 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 plant costs disallowed for the three months ended and nine months ended September 30, 2004 was the result of the decision of the PUCN to disallow recovery of a portion of the costs associated with the Pinon Pine power plant project. See the 2004 10-K, Note 3, Regulatory Actions for further discussion.

SPPC’s Other expense for the three months and nine months ended September 30, 2005 differed slightly compared to the same periods in 2004, due to various charges, all of which were not individually significant.

SPPC’s income taxes- other income and expense for the three months ended September 30, 2005, increased compared to the same period in 2004, substantially as a result of an increase in pretax other income. Income taxes — other income and expense recorded income tax expense for the nine months ended September 30, 2005 compared to an income tax benefit recognized during the same period in 2004. The 2004 tax benefit was recognized primarily as a result of an impairment charge associated with the Piñon Pine generating facility during the second quarter of 2004. See Note 3, of the Notes to the Financial Statements, Regulatory Actions, of the 2004 10-K for additional information regarding the impairment charge.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows increased during the nine months ended September 30, 2005, when compared to the same period in 2004, as a result of an increase in cash flows from operating activities partially offset by an increase in cash used in investing activities. Cash flows from operating activities were higher in 2005 due to rate increases that became effective in the second quarter of 2004, which was the result of SPPC’s General and Deferred Rate Cases (refer to “Regulatory Proceedings” in the 2004 10-K). Also causing an increase in cash flow from operations was the $11 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility and changes in accounts receivables for tax sharing agreements. Cash flows used in investing activities increased primarily as a result of construction activity related to growth.

LIQUIDITY AND CAPITAL RESOURCES

SPPC had cash and cash equivalents of approximately $74.2 million at September 30, 2005, not including $11 million in restricted cash which was deposited into escrow in connection with the stay of the Enron Judgment, and as of November 4, 2005, additional liquidity in the amount of $250 million as discussed in financing transactions. As of September 30, 2005, SPPC had no direct borrowings and$2.5 million of letters of credit outstanding under the revolving credit facility.

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 September 30, 2005, SPPC has incurred approximately $83.5 million in construction expenditures.

During the three months and nine months ended September 30, 2005, there were no material changes to contractual obligations as set forth in SPPC’s 2004 10-K.

Financing Transactions

Amended Credit Facility

On November 4, 2005, SPPC amended and restated its existing secured $50 million revolving credit facility, maturing in October 2007, increasing the size of the facility to $250 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association; however, the total amount of the credit facility will be reduced by $200 million in November 2006 unless SPPC obtains long-term PUCN authority for this amount prior to such date. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an alternate base rate or a Eurodollar rate plus a margin that varies based upon SPPC’s credit rating by S&P and Moody’s. Currently, SPPC’s alternate base rate margin is 1.00% and its Eurodollar margin is 2.00%.

Collateral

The revolving credit facility is secured by SPPC’s General and Refunding Mortgage Bonds; however, in the event that SPPC obtains an unsecured debt rating from at least two rating agencies that is at least BBB- from S&P and Fitch or Baa3 from Moody’s, the General and Refunding Mortgage Bonds securing the revolving credit facility will be released.

Conditions to Borrowing

The credit agreement contains customary conditions to borrowing including requirements that no material litigation, defaults or other events that could have a material adverse effect on SPPC’s business shall have occurred. In the event that SPPC’s unsecured debt ratings meet the conditions discussed above, the requirement that no material adverse changes shall have occurred ceases to be a condition to borrowing under the credit agreement.

Financial Covenants

The 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.

Dividend Restriction

The credit agreement contains a dividend limitation similar to certain of SPPC’s existing dividend limitations. The limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR’s indebtedness and payment obligations on account of SPR’s Premium Income Equity Securities) provided that:

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

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

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

The credit agreement also permits SPPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed $50 million from the date of the establishment of the credit agreement.

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

	•		there are no defaults or events of default with respect to the credit agreement,

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

	•		the total amount of such dividends is less than the sum of:

	•		50% of SPPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of the establishment of the revolving credit facility, plus

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

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

The dividend restrictions described above shall not apply if (i) SPPC obtains an unsecured debt rating on its general and refunding bonds securing the credit facility from at least two rating agencies that is at least BBB- from S&P and Fitch or Baa3 from Moody’s, in each case with a stable or better outlook, and (ii) there are no defaults or events of default with respect to the credit agreement.

Restriction on Additional Indebtedness

The credit agreement also restricts SPPC from incurring any additional indebtedness unless:

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

	•		the debt incurred is specifically permitted under the terms of the credit agreement, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy and gas suppliers, or indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Integrated Resource Plan.

Other Restrictions

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

Defaults

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

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

Mortgage Indentures

SPPC’s First Mortgage Indenture creates a first priority lien on substantially all of SPPC’s properties in Nevada and California. As of September 30, 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 September 30, 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 September 30, 2005, SPPC had the capacity to issue approximately $385 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 restricted covenants contained various series of SPPC’s outstanding General and Refunding Mortgage Securities, its Amended and Restated Revolving Credit Agreement and SPR’s outstanding senior notes 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 (except for as discussed above in Amended Credit Facility), SPPC would have been able to issue additional indebtedness. SPPC’s most restrictive limitation on indebtedness is within certain supplemental indentures of SPR, including SPR’s $335 million 8 5/8% Senior Unsecured Notes due March 15, 2014, $99.1 million 7.803% Senior Notes due June 15, 2012, $140.9 million Series A Floating Rate Senior Notes due November 16, 2005 and $99.1 million Series B Floating Rate Senior Notes due November 16, 2005, contain restrictions on SPR’s, NPC’s and SPPC’s ability to issue additional indebtedness. As of September 30, 2005, SPR, NPC and SPPC are restricted to issuing no more than approximately $546 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.75% based upon SPR’s most recent debt issuance, unless the indebtedness being issued is specifically permitted under the terms of SPR’s 6.75% Senior Notes due 2017. 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 September 30, 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 (except for as discussed above in Amended Credit Facility).

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 (except for as discussed above in Amended Credit Facility).

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 recovery 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 was 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 energy rates, which are reflected in the NPC’s Base Tariff Energy Rate (BTER).

Nevada Power Company Base Tariff Energy Rate Update

The request represents an increase of 3.74% for the average residential customer and 3.53% for all other customer classes.

On September 27, 2005, the PUCN issued an order approving the BTER rate changes requested in NPC’s filing.

Nevada Power Company Amendments to its Integrated Resource Plan

Long Term Power Exchange

On May 19, 2005, the PUCN approved the Power Exchange Agreement, which became effective June 1, 2005.

Silverhawk Plant Acquisition and Clark Generating Unit Retirements

	•		The Interim Purchased Power Agreement (in effect from October 1, 2005 and until final approvals of acquisition) is prudent and NPC may recover all just and reasonable costs through the deferred energy accounting process.

	•		The terms and conditions of the Silverhawk acquisition agreement are just and reasonable and NPC may recover all just and reasonable acquisition costs in general rates. The stipulation recognizes the $221.4 million acquisition cost as estimated by NPC.

	•		NPC is authorized to issue up to $210 million of long term financing through December 31, 2006 for the Silverhawk facility acquisition or other lawful public utility purposes.

	•		It is prudent for NPC to retire the Clark Generating Station Units 1, 2, and 3 and for NPC to commence the permitting process for replacement units at that site.

On September 23, 2005, the PUCN issued its order approving the stipulation.

Not included in the above stipulation was NPC’s requested accounting treatment for retirement and decommissioning costs. On September 13, 2005, NPC filed an amended application requesting: 1) authorization to set up a regulatory asset account for the net book value and decommissioning costs for the Clark Units 1, 2 and 3 and that any balance in that account be included in rate base in NPC’s next general rate case with a four year amortization schedule, 2) authorization to use decremental operations and maintenance costs associated with the shutdown of the Mohave generating station to offset the incremental operations and maintenance costs resulting from the addition of the Lenzie and Silverhawk generating units.

The PUCN has scheduled a hearing for November 16-17, 2005 and NPC expects a decision will be issued in the fourth quarter 2005.

Sierra Pacific Power Company 2005 Electric and Gas General Rate Cases

On October 3, 2005, SPPC filed a Gas general rate case along with its statutorily required Electric general rate case. SPPC’s last Gas general rate case was filed in 1992 and the last electric general rate case was filed in 2003. The following items are requested in the filings:

	•		Electric general revenue increase: $27 million or 3.4% effective May 1, 2006

	•		Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006

	•		Electric Return on Equity and Rate of Return: 11.4% and 9.27%

	•		Gas Return on Equity and Rate of Return: 11.4% and 8.29%

	•		Approval to continue to recover an allocated amount of the 1999 NPC and SPPC merger costs from Electric customers

	•		Approval to recover an allocated amount of the 1999 NPC and SPPC merger costs from Gas customers

	•		New depreciation rates for Gas and Electric facilities

A pre-hearing conference has been scheduled for the gas case on November 9, 2005 and for the electric case on November 17, 2005. A decision on these cases is due early in the second quarter of 2006.