- Quarterly Report (10-Q)

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, 2008


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	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	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 d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 367-5000

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

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

Indicate by check mark whether any registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer", "accelerated filer”, "non-accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Sierra Pacific Resources:	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Nevada Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
Sierra Pacific Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ (Response applicable to all registrants)

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 October 31, 2008
Common Stock, $1.00 par value of Sierra Pacific Resources		234,149,821 Shares

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

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

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

Table of Contents

SIERRA PACIFIC RESOURCES

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2008

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements

Sierra Pacific Resources —
Consolidated Balance Sheets — September 30, 2008 and December 31, 20 07			3
Consolidated Income Statements — Three Months and Nine Months Ended September 30, 2008 and 200 7			4
Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2008 and 200 7			5

Nevada Power Company —
Consolidated Balance Sheets — September 30, 2008 and December 31, 2007			6
Consolidated Income Statements — Three Months and Nine Months Ended September 30, 2008 and 200 7			7
Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2008 and 200 7			8

Sierra Pacific Power Company —
Consolidated Balance Sheets — September 30, 2008 and December 31, 2007			9
Consolidated Income Statements — Three Months and Nine Months Ended September 30, 2008 and 200 7			10
Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2008 and 200 7			11

Condensed Notes to Consolidated Financial Statements			12

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Sierra Pacific Resources			34
Nevada Power Company			38
Sierra Pacific Power Company			45

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk			55

ITEM 4 and 4T. Controls and Procedures			55

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings			56
ITEM 1A. Risk Factors			56
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			56
ITEM 3. Defaults Upon Senior Securities			56
ITEM 4. Submission of Matters to a Vote of Security Holders			56
ITEM 5. Other Information			56
ITEM 6. Exhibits			57

Signature Page and Certifications			58

Table of Contents

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

		September 30,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	9,278,831	$	8,468,711
Less accumulated provision for depreciation			2,607,546		2,526,379
			6,671,285		5,942,332
Construction work-in-progress			790,970		1,068,666
			7,462,255		7,010,998

Investments and other property, net			31,037		31,061

Current Assets:
Cash and cash equivalents			229,145		129,140
Accounts receivable less allowance for uncollectible accounts:
	2008- $33,823, 2007-$36,061		528,443		434,359
Deferred energy costs - electric (Note 1)			43,509		75,948
Materials, supplies and fuel, at average cost			130,164		117,483
Risk management assets (Note 5)			17,387		22,286
Deferred income taxes			82,951		43,295
Other			41,903		45,909
			1,073,502		868,420
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			291,223		205,030
Regulatory tax asset			267,445		267,848
Regulatory asset for pension plans			185,295		133,984
Other regulatory assets			777,568		758,287
Risk management assets (Note 5)			8,893		12,429
Risk management regulatory assets - net (Note 5)			210,346		26,067
Unamortized debt issuance costs			64,494		65,218
Other			158,272		85,408
			1,963,536		1,554,271
TOTAL ASSETS		$	10,530,330	$	9,464,750
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,156,607	$	2,996,575
Long-term debt			4,793,078		4,137,864
			7,949,685		7,134,439
Current Liabilities:
Current maturities of long-term debt			9,794		110,285
Accounts payable			348,898		357,867
Accrued interest			75,970		69,485
Accrued salaries and benefits			38,664		35,020
Current income taxes payable			-		3,544
Risk management liabilities (Note 5)			185,759		39,509
Accrued taxes			8,378		8,336
Deferred energy costs - electric (Note 1)			3,950		17,573
Deferred energy costs - gas (Note 1)			10,869		11,369
Other current liabilities			89,150		65,991
			771,432		718,979
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			982,987		852,630
Deferred investment tax credit			26,665		28,895
Regulatory tax liability			26,273		28,445
Customer advances for construction			89,108		100,125
Accrued retirement benefits			121,872		77,525
Risk management liabilities (Note 5)			35,201		7,369
Regulatory liabilities			326,518		304,026
Other			200,589		212,317
			1,809,213		1,611,332
TOTAL CAPITALIZATION AND LIABILITIES		$	10,530,330	$	9,464,750

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

Table of Contents

SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

OPERATING REVENUES:
Electric	$	1,098,744		$	1,185,205		$	2,624,832		$	2,676,713
Gas		19,379			20,839			137,125			137,337
Other		8			6			19			325
		1,118,131			1,206,050			2,761,976			2,814,375
OPERATING EXPENSES:
Operation:
Purchased power		383,329			410,467			828,635			851,396
Fuel for power generation		332,872			238,180			825,105			658,392
Gas purchased for resale		13,760			11,661			108,288			103,169
Deferral of energy costs - electric - net		(89,575	)		66,660			(56,679	)		193,954
Deferral of energy costs - gas - net		(725	)		2,594			(2,296	)		4,203
Other		105,087			98,399			295,409			275,414
Maintenance		20,337			23,308			64,931			77,686
Depreciation and amortization		59,245			58,876			185,656			174,787
Taxes:
Income taxes		61,148			69,677			82,695			76,166
Other than income		13,701			13,091			40,266			37,710
		899,179			992,913			2,372,010			2,452,877
OPERATING INCOME		218,952			213,137			389,966			361,498

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		7,865			9,214			32,935			22,393
Interest accrued on deferred energy		2,349			4,633			4,042			13,020
Carrying charge for Lenzie		-			-			-			16,080
Reinstated interest on deferred energy		-			-			-			11,076
Other income		6,583			4,605			24,787			18,293
Other expense		(3,007	)		(5,044	)		(10,804	)		(18,110	)
Income taxes		(4,263	)		(4,572	)		(16,451	)		(20,630	)
		9,527			8,836			34,509			42,122
Total Income Before Interest Charges		228,479			221,973			424,475			403,620

INTEREST CHARGES:
Long-term debt		75,483			69,686			215,826			204,681
Other		8,391			7,626			23,092			23,625
Allowance for borrowed funds used during construction		(6,178	)		(7,561	)		(25,418	)		(18,269	)
		77,696			69,751			213,500			210,037

NET INCOME APPLICABLE TO COMMON STOCK	$	150,783		$	152,222		$	210,975		$	193,583

Amount per share basic and diluted (Note 7)
Net Income applicable to common stock	$	0.64		$	0.69		$	0.90		$	0.87

Weighted Average Shares of Common Stock Outstanding - basic		234,096,559			221,612,243			233,975,552			221,424,682
Weighted Average Shares of Common Stock Outstanding - diluted		234,655,132			221,968,802			234,499,269			221,783,424
Dividends Declared Per Common Share	$	0.08		$	0.08		$	0.24		$	0.08

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

Table of Contents

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income applicable to common stock	$	210,975		$	193,583
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		185,656			174,787
Deferred taxes and deferred investment tax credit		172,425			103,598
AFUDC		(32,935	)		(22,393	)
Amortization of deferred energy costs - electric		140,522			172,046
Amortization of deferred energy costs - gas		(983	)		734
Deferral of energy costs - electric		(203,396	)		11,900
Deferral of energy costs - gas		483			3,749
Carrying charge on Lenzie plant		-			(16,080	)
Reinstated interest on deferred energy		-			(11,076	)
Other, net		13,087			26,518
Changes in certain assets and liabilities:
Accounts receivable		(139,755	)		(146,865	)
Materials, supplies and fuel		(12,682	)		(13,588	)
Other current assets		4,005			1,982
Accounts payable		(33,712	)		37,232
Accrued retirement benefits		(13,839	)		(92,291	)
Other current liabilities		33,403			24,422
Risk Management assets and liabilities		(1,763	)		11,805
Other deferred assets		(34,433	)		7,964
Other regulatory assets		(50,702	)		(15,096	)
Other liabilities		(12,102	)		(9,872	)
Net Cash from Operating Activities		224,254			443,058

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(671,918	)		(899,605	)
Customer advances for construction		(11,018	)		4,749
Contributions in aid of construction		57,437			41,243
Investments and other property - net		4,312			2,928
Net Cash used by Investing Activities		(621,187	)		(850,685	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,420,002			1,201,354
Retirement of long-term debt		(871,987	)		(800,471	)
Sale of Common Stock		5,195			4,525
Proceeds from exercise of stock option		-			5,112
Dividends paid		(56,272	)		(17,743	)
Net Cash from Financing Activities		496,938			392,777

Net Increase (Decrease) in Cash and Cash Equivalents		100,005			(14,850	)
Beginning Balance in Cash and Cash Equivalents		129,140			115,709
Ending Balance in Cash and Cash Equivalents	$	229,145		$	100,859

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	213,857		$	193,549
Income taxes	$	16,897		$	9,727


The accompanying notes are an integral part of the financial statements

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

		September 30,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	5,898,778	$	5,571,492
Less accumulated provision for depreciation			1,460,458		1,407,334
			4,438,320		4,164,158
Construction work-in-progress			660,722		576,127
			5,099,042		4,740,285

Investments and other property, net			19,662		19,544

Current Assets:
Cash and cash equivalents			177,734		37,001
Accounts receivable less allowance for uncollectible accounts:
	2008- $31,462 , 2007-$30,392		396,035		274,242
Deferred energy costs - electric (Note 1)			43,509		75,948
Materials, supplies and fuel, at average cost			78,202		68,671
Risk management assets (Note 5)			12,844		16,078
Intercompany income taxes receivable			49,727		-
Deferred income taxes			-		2,383
Other			29,585		28,352
			787,636		502,675
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			291,223		205,030
Regulatory tax asset			170,383		165,257
Regulatory asset for pension plans			102,509		86,909
Other regulatory assets			538,111		524,460
Risk management assets (Note 5)			6,502		9,069
Risk management regulatory assets - net (Note 5)			146,907		17,186
Unamortized debt issuance costs			36,865		36,551
Other			138,561		70,403
			1,431,061		1,114,865
TOTAL ASSETS		$	7,337,401	$	6,377,369
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,629,078	$	2,376,740
Long-term debt			2,975,201		2,528,141
			5,604,279		4,904,881
Current Liabilities:
Current maturities of long-term debt			8,656		8,642
Accounts payable			246,397		231,205
Accounts payable, affiliated companies			27,628		32,706
Accrued interest			54,539		41,920
Dividends declared			-		10,907
Accrued salaries and benefits			20,188		16,881
Current income taxes payable			-		3,544
Intercompany income taxes payable			-		15,403
Deferred income taxes			6,224		-
Risk management liabilities (Note 5)			132,458		26,982
Accrued taxes			4,268		4,529
Other current liabilities			74,012		50,902
			574,370		443,621
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			691,955		585,168
Deferred investment tax credit			10,293		11,169
Regulatory tax liability			9,136		10,038
Customer advances for construction			45,939		58,890
Accrued retirement benefits			46,281		25,693
Risk management liabilities (Note 5)			22,571		5,116
Regulatory liabilities			175,376		168,381
Other			157,201		164,412
			1,158,752		1,028,867

TOTAL CAPITALIZATION AND LIABILITIES		$	7,337,401	$	6,377,369

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

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
OPERATING REVENUES:
Electric	$	826,825		$	894,226		$	1,866,220		$	1,887,499

OPERATING EXPENSES:
Operation:
Purchased power		319,324			313,487			577,161			584,797
Fuel for power generation		240,027			166,284			613,968			471,142
Deferral of energy costs-net		(80,191	)		54,868			(44,107	)		149,531
Other		69,432			61,400			189,144			167,401
Maintenance		12,469			16,360			42,727			54,143
Depreciation and amortization		37,902			38,151			120,855			112,745
Taxes:
Income taxes		54,595			65,407			69,592			65,849
Other than income		8,266			8,005			24,015			22,431
		661,824			723,962			1,593,355			1,628,039
OPERATING INCOME		165,001			170,264			272,865			259,460

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,543			4,701			21,093			11,046
Interest accrued on deferred energy		2,803			4,573			5,681			11,849
Carrying charge for Lenzie		-			-			-			16,080
Reinstated interest on deferred energy		-			-			-			11,076
Other income		4,116			2,315			12,970			10,345
Other expense		(2,028	)		(1,346	)		(5,045	)		(8,772	)
Income taxes		(3,828	)		(3,518	)		(11,350	)		(17,649	)
		7,606			6,725			23,349			33,975
Total Income Before Interest Charges		172,607			176,989			296,214			293,435

INTEREST CHARGES:
Long-term debt		46,662			41,955			129,283			123,029
Other		6,737			5,876			17,952			18,315
Allowance for borrowed funds used during construction		(5,128	)		(3,936	)		(16,503	)		(9,189	)
		48,271			43,895			130,732			132,155

NET INCOME	$	124,336		$	133,094		$	165,482		$	161,280


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

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	165,482		$	161,280
Adjustments to reconcile net income to net cash from or
operating activities:
Depreciation and amortization		120,855			112,745
Deferred taxes and deferred investment tax credit		89,543			76,188
AFUDC		(21,093	)		(11,046	)
Amortization of deferred energy costs		123,875			137,633
Deferral of energy costs		(173,522	)		700
Carrying charge on Lenzie plant		-			(16,080	)
Reinstated interest on deferred energy		-			(11,076	)
Other, net		2,659			3,077
Changes in certain assets and liabilities:
Accounts receivable		(143,891	)		(180,404	)
Materials, supplies and fuel		(9,531	)		(7,189	)
Other current assets		(1,233	)		(4,680	)
Accounts payable		(21,048	)		60,407
Accrued retirement benefits		(1,741	)		(49,794	)
Other current liabilities		38,775			18,298
Risk management assets and liabilities		(989	)		5,490
Other deferred assets		(35,291	)		6,495
Other regulatory assets		(36,540	)		(11,538	)
Other liabilities		(8,113	)		8,101
Net Cash from Operating Activities		88,197			298,607

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(506,680	)		(573,921	)
Customer advances for construction		(12,951	)		1,428
Contributions in aid of construction		49,108			26,240
Investments and other property - net		2,719			2,899
Net Cash used by Investing Activities		(467,804	)		(543,354	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		878,034			699,254
Retirement of long-term debt		(435,787	)		(422,780	)
Additional investment by parent company		133,000			-
Dividends paid		(54,907	)		(23,472	)
Net Cash from Financing Activities		520,340			253,002

Net Increase in Cash and Cash Equivalents		140,733			8,255
Beginning Balance in Cash and Cash Equivalents		37,001			36,633
Ending Balance in Cash and Cash Equivalents	$	177,734		$	44,888

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	120,749		$	115,047
Income taxes	$	15,534		$	6,760

The accompanying notes are an integral part of the financial statements

Table of Contents

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

		September 30,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	3,380,053	$	2,897,219
Less accumulated provision for depreciation			1,147,088		1,119,045
			2,232,965		1,778,174
Construction work-in-progress			130,248		492,539
			2,363,213		2,270,713

Investments and other property, net			424		570

Current Assets:
Cash and cash equivalents			29,343		23,807
Accounts receivable less allowance for uncollectible accounts:
	2008 - $2,361; 2007 - $5,669		132,290		160,014
Materials, supplies and fuel, at average cost			51,941		48,799
Risk management assets (Note 5)			4,543		6,208
Intercompany income taxes receivable			39,202		-
Deferred income taxes			12,909		17,728
Other			11,767		17,255
			281,995		273,811
Deferred Charges and Other Assets:
Regulatory tax asset			97,062		102,591
Regulatory asset for pension plans			76,239		43,778
Other regulatory assets			239,458		233,827
Risk management assets (Note 5)			2,391		3,360
Risk management regulatory assets - net (Note 5)			63,439		8,881
Unamortized debt issuance costs			19,843		19,976
Other			19,525		19,017
			517,957		431,430
TOTAL ASSETS		$	3,163,589	$	2,976,524
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	1,015,690	$	1,001,840
Long-term debt			1,292,867		1,084,550
			2,308,557		2,086,390
Current Liabilities:
Current maturities of long-term debt			1,139		101,643
Accounts payable			75,695		94,722
Accounts payable, affiliated companies			15,629		19,288
Accrued interest			17,307		15,750
Dividends declared			-		5,333
Accrued salaries and benefits			15,582		14,830
Intercompany income taxes payable			-		2,479
Risk management liabilities (Note 5)			53,301		12,527
Accrued taxes			3,975		3,542
Deferred energy costs - electric (Note 1)			3,950		17,573
Deferred energy costs - gas (Note 1)			10,869		11,369
Other current liabilities			15,136		15,015
			212,583		314,071
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			291,028		267,801
Deferred investment tax credit			16,372		17,726
Regulatory tax liability			17,137		18,407
Customer advances for construction			43,169		41,235
Accrued retirement benefits			68,671		48,025
Risk management liabilities (Note 5)			12,630		2,253
Regulatory liabilities			151,142		135,645
Other			42,300		44,971
			642,449		576,063
TOTAL CAPITALIZATION AND LIABILITIES		$	3,163,589	$	2,976,524

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

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
OPERATING REVENUES:
Electric	$	271,919		$	290,979		$	758,612		$	789,214
Gas		19,379			20,839			137,125			137,337
		291,298			311,818			895,737			926,551
OPERATING EXPENSES:
Operation:
Purchased power		64,005			96,980			251,474			266,599
Fuel for power generation		92,845			71,896			211,137			187,250
Gas purchased for resale		13,760			11,661			108,288			103,169
Deferral of energy costs - electric - net		(9,384	)		11,792			(12,572	)		44,423
Deferral of energy costs - gas - net		(725	)		2,594			(2,296	)		4,203
Other		35,474			36,228			103,744			105,070
Maintenance		7,868			6,948			22,204			23,543
Depreciation and amortization		21,343			20,726			64,801			62,043
Taxes:
Income taxes		10,602			9,825			24,213			20,871
Other than income		5,402			5,050			16,128			15,138
		241,190			273,700			787,121			832,309
OPERATING INCOME		50,108			38,118			108,616			94,242

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		1,322			4,513			11,842			11,347
Interest accrued on deferred energy		(454	)		60			(1,639	)		1,171
Other income		2,367			1,865			11,331			6,707
Other expense		(749	)		(2,938	)		(5,430	)		(7,143	)
Income taxes		(683	)		(1,104	)		(5,210	)		(3,597	)
		1,803			2,396			10,894			8,485
Total Income Before Interest Charges		51,911			40,514			119,510			102,727

INTEREST CHARGES:
Long-term debt		18,635			17,096			55,975			49,746
Other		1,407			1,491			4,398			4,533
Allowance for borrowed funds used during construction		(1,050	)		(3,625	)		(8,915	)		(9,080	)
		18,992			14,962			51,458			45,199

NET INCOME	$	32,919		$	25,552		$	68,052		$	57,528


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

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	68,052		$	57,528
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		64,801			62,043
Deferred taxes and deferred investment tax credit		28,472			(25,456	)
AFUDC		(11,842	)		(11,347	)
Amortization of deferred energy costs - electric		16,647			34,413
Amortization of deferred energy costs - gas		(983	)		734
Deferral of energy costs - electric		(29,874	)		11,200
Deferral of energy costs - gas		483			3,749
Other, net		14,476			22,141
Changes in certain assets and liabilities:
Accounts receivable		4,152			33,257
Materials, supplies and fuel		(3,142	)		(6,399	)
Other current assets		5,488			6,512
Accounts payable		(16,267	)		3,310
Accrued retirement b enefits		(15,789	)		(36,139	)
Other current liabilities		2,864			13,940
Risk management assets and liabilities		(774	)		6,315
Other deferred assets		858			1,468
Other regulatory assets		(14,162	)		(3,558	)
Other liabilities		(2,142	)		(3,896	)
Net Cash from Operating Activities		111,318			169,815

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(165,238	)		(325,684	)
Customer advances for construction		1,933			3,321
Contributions in aid of construction		8,329			15,004
Investments and other property - net		1,597			25
Net Cash used by Investing Activities		(153,379	)		(307,334	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		541,968			502,100
Retirement of long-term debt		(436,038	)		(377,531	)
Investment by parent company		20,000			-
Dividends paid		(78,333	)		(11,736	)
Net Cash from Financing Activities		47,597			112,833

Net Increase (Decrease) in Cash and Cash Equivalents		5,536			(24,686	)
Beginning Balance in Cash and Cash Equivalents		23,807			53,260
Ending Balance in Cash and Cash Equivalents	$	29,343		$	28,574

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	54,849		$	38,854
Income taxes	$	19		$	64

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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both utility and non-utility operations are as follows:

Basis of Presentation

The consolidated financial statements 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"), Sierra Gas Holding Company (SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications (SPC) and Sierra Water Development Company (SWDC). 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 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 and/or Form 10-K/A for the year ended December 31, 2007 (collectively, the “2007 Form 10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the nine months ended September 30, 2008, are not necessarily indicative of the results to be expected for the full year.

Deferral of Energy Costs

NPC and SPPC follow deferred energy accounting. See Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in NPC's and SPPC's 2007 Form 10-K, for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of September 30, 2008 (dollars in thousands):

	September 30, 2008
Description	NPC Electric			SPPC Electric			SPPC Gas			SPR Total

Unamortized balances approved for collection in current rates
as of January 1, 2008	$	79,924		$	13,257		$	(1,208	)	$	91,973
Balances approved in 2008 DEAA (1)(2)		(44,424	)		(34,300	)		(10,174	)		(88,898	)
Cumulative Balance request in 2008 DEAA		35,500			(21,043	)		(11,382	)		3,075
2008 amortization of approved balances		(89,653	)		(13,098	)		983			(101,768	)
2008 deferred energy costs not yet requested		175,056			29,267			(470	)		203,853
Western Energy Crisis Rate Case (effective 6/07, 3 years)		46,711			-			-			46,711
Reinstatement of deferred energy (effective 6/07, 10 years)		167,118			-			-			167,118
Cumulative CPUC balance (3)		-			924			-			924
Total	$	334,732		$	(3,950	)	$	(10,869	)	$	319,913

Current Assets
Deferred energy costs – electric	$	43,509		$	-		$	-		$	43,509
Deferred Assets
Deferred energy costs - electric		291,223			-			-			291,223
Current Liabilities
Deferred energy costs – electric		-			(3,950	)		-			(3,950	)
Deferred energy costs – gas		-			-			(10,869	)		(10,869	)
Total	$	334,732		$	(3,950	)	$	(10,869	)	$	319,913

(1)	Credit balances represent potential refunds to the Utilities’ customers.
(2)	DEAA is defined as Deferred Energy Accounting Adjustment.
(3)	CPUC is defined as California Public Utility Commission.

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Recent Pronouncements

SFAS 161

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB Statement No. 133 (“SFAS 161”) which is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The purpose of SFAS 161 is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. The Utilities are currently evaluating the additional disclosure requirements but do not expect their disclosure to change significantly.

SFAS 157

Effective January 1, 2008, SPR and the Utilities adopted the provisions of SFAS No. 157, Fair Value Measurements (“SFAS 157”) which defines fair value, establishes criteria when measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date,” or the “exit price.” Accordingly, an entity must now determine the fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. Additionally, SFAS No. 157 establishes a fair value hierarchy which gives precedence to fair value measurements calculated using observable inputs to those using unobservable inputs. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008 did not have a material impact on SPR or the Utilities financial condition and results of operations; however, it did require expanded disclosures with respect to fair value measurements. See Note 5, Derivative and Hedging Activities for the expanded disclosures.

In February 2008, the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. SPR and the Utilities will be required to adopt those provisions of SFAS No. 157 beginning January 1, 2009. In October 2008, the FASB issued Staff Position No. 157-3 Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active, (“FSP 157-3”) FSP157-3 is effective immediately. SPR and the Utilities considered the guidance in FSP 157-3 and have determined that the adoption did not have a material impact on the consolidated financial statements.

NOTE 2. SEGMENT INFORMATION

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

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 gross margin. Gross margin, which the Utilities calculate as operating revenues less fuel, purchased power, and deferred energy costs, provides a measure of income available to support the other operating expenses of the Utilities. Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands).

Three Months Ended	NPC			SPPC			SPPC			SPPC			SPR			SPR
September 30, 2008	Electric			Electric			Gas			Total			Other			Consolidated
Operating Revenues	$	826,825		$	271,919		$	19,379		$	291,298		$	8		$	1,118,131

Energy Costs:
Purchased power		319,324			64,005			-			64,005			-			383,329
Fuel for power generation		240,027			92,845			-			92,845			-			332,872
Gas purchased for resale		-			-			13,760			13,760			-			13,760
Deferred energy costs - net		(80,191	)		(9,384	)		(725	)		(10,109	)		-			(90,300	)
		479,160			147,466			13,035			160,501			-			639,661

Gross Margin	$	347,665		$	124,453		$	6,344		$	130,797		$	8		$	478,470


Other		69,432									35,474			181			105,087
Maintenance		12,469									7,868			-			20,337
Depreciation and amortization		37,902									21,343			-			59,245
Taxes:
Income taxes		54,595									10,602			(4,049	)		61,148
Other than income		8,266									5,402			33			13,701

Operating Income	$	165,001								$	50,108		$	3,843		$	218,952

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Nine Months Ended	NPC			SPPC			SPPC			SPPC			SPR			SPR
September 30, 2008	Electric			Electric			Gas			Total			Other			Consolidated
Operating Revenues	$	1,866,220		$	758,612		$	137,125		$	895,737		$	19		$	2,761,976

Energy Costs:
Purchased power		577,161			251,474			-			251,474			-			828,635
Fuel for power generation		613,968			211,137			-			211,137			-			825,105
Gas purchased for resale		-			-			108,288			108,288			-			108,288
Deferred energy costs - net		(44,107	)		(12,572	)		(2,296	)		(14,868	)		-			(58,975	)
		1,147,022			450,039			105,992			556,031			-			1,703,053

Gross Margin	$	719,198		$	308,573		$	31,133		$	339,706		$	19		$	1,058,923


Other		189,144									103,744			2,521			295,409
Maintenance		42,727									22,204			-			64,931
Depreciation and amortization		120,855									64,801			-			185,656
Taxes:
Income taxes		69,592									24,213			(11,110	)		82,695
Other than income		24,015									16,128			123			40,266

Operating Income	$	272,865								$	108,616		$	8,485		$	389,966

Three Months Ended	NPC		SPPC		SPPC		SPPC		SPR			SPR
September 30, 2007	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	894,226	$	290,979	$	20,839	$	311,818	$	6		$	1,206,050

Energy Costs:
Purchased power		313,487		96,980		-		96,980		-			410,467
Fuel for power generation		166,284		71,896		-		71,896		-			238,180
Gas purchased for resale		-		-		11,661		11,661		-			11,661
Deferred energy costs - net		54,868		11,792		2,594		14,386		-			69,254
		534,639		180,668		14,255		194,923		-			729,562

Gross Margin	$	359,587	$	110,311	$	6,584	$	116,895	$	6		$	476,488


Other		61,400						36,228		771			98,399
Maintenance		16,360						6,948		-			23,308
Depreciation and amortization		38,151						20,726		(1	)		58,876
Taxes:
Income taxes		65,407						9,825		(5,555	)		69,677
Other than income		8,005						5,050		36			13,091

Operating Income	$	170,264					$	38,118	$	4,755		$	213,137

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Nine Months Ended	NPC		SPPC		SPPC		SPPC		SPR			SPR
September 30, 2007	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	1,887,499	$	789,214	$	137,337	$	926,551	$	325		$	2,814,375

Energy Costs:
Purchased power		584,797		266,599		-		266,599		-			851,396
Fuel for power generation		471,142		187,250		-		187,250		-			658,392
Gas purchased for resale		-		-		103,169		103,169		-			103,169
Deferred energy costs - net		149,531		44,423		4,203		48,626		-			198,157
		1,205,470		498,272		107,372		605,644		-			1,811,114

Gross Margin	$	682,029	$	290,942	$	29,965	$	320,907	$	325		$	1,003,261


Other		167,401						105,070		2,943			275,414
Maintenance		54,143						23,543		-			77,686
Depreciation and amortization		112,745						62,043		(1	)		174,787
Taxes:
Income taxes		65,849						20,871		(10,554	)		76,166
Other than income		22,431						15,138		141			37,710

Operating Income	$	259,460					$	94,242	$	7,796		$	361,498

NOTE 3. REGULATORY ACTIONS

Pending Regulatory Actions

Nevada Power Company

NPC Ninth Amendment to its Integrated Resource Plan (IRP)

In August 2008, NPC filed its ninth amendment to its IRP. In the amendment, NPC seeks approval to establish a regulatory asset for the 50% interest in the Carson Lake Project a minimum of 30 megawatts (MW) (nominally rated) of renewable energy (from a nominal net 24 MW to 40 MW) under the terms of a Joint Operating Agreement with an affiliate of Ormat Technologies Inc., and related operating and maintenance costs, depreciation and return on the plant until such time as it is included in general rates. Hearings are scheduled for late November 2008.

Sierra Pacific Power Company

SPPC California General Rate Case

In July 2008, SPPC filed a general rate case. SPPC requested the following:

·	Increase in general rates of $6.6 million, approximately an 8.1% increase;

·	Return on equity (ROE) and rate of return (ROR) of 11.4% and 8.81%, respectively;

·	Authorization to recover the costs of major plant additions, which include the new Tracy 541 MW (nominally rated) combined cycle generating plant, distribution plant additions and an increase to the California Energy Efficiency Program;

·	A two-part mechanism to recover changes in non-energy cost adjustment clause costs incurred during the two years between rate cases.

If approved, the new rates would be effective April 1, 2009.

Settled Regulatory Actions

Nevada Power Company

NPC Eighth Amendment to 2006 IRP

In May 2008, NPC filed its eighth amendment to its IRP. The PUCN issued its order in October 2008, which approved:

·	the purchase of the 598 MW (nominally rated) combined cycle Bighorn Power Plant from Reliant Energy LLC and Reliant Energy Asset Management LLC for approximately $510 million including costs for inventory and other closing costs and adjustments. The purchase was completed in October 2008.

construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen site with a scheduled commercial operation date of June 1, 2011. The estimated cost of this project is approximately $682 million (excluding allowance for funds used during construction). Additionally, the PUCN approved NPC’s request to include Harry Allen construction work in progress (“CWIP”) in rate base. On October 15, 2008, the Office of the Attorney General, Bureau of Consumer Protection (“BCP”), filed a petition for reconsideration and/or rehearing of that part of the PUCN’s Order on NPC’s eighth amendment to its 2006 IRP approving the construction of Harry Allen. NPC intends to oppose this petition but cannot predict how the PUCN will rule on the petition.

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Additionally, the PUCN, in its order, outlined certain minimum information regarding the Ely Energy Center (EEC) that shall be provided in NPC’s 2009 IRP filing including but not limited to an update of the engineering, construction and then current cost estimates for the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, an update of environmental costs and economic benefits attributed to the EEC and an update on the status of all required permits. Additionally, modification of the in-service dates will be addressed in the 2009 IRP filing. Finally, the PUCN directed NPC to continue to monitor load growth and congestion for the Sunrise Tap area and to address the issue of appropriate timing and expenditures for the Sunrise-500 kV Tap transmission line project in its 2009 IRP filing.

NPC 2008 Deferred Energy Rate Case

In February 2008, NPC filed applications to create a new DEAA rate and to update the going forward Base Tariff Energy Rate (BTER). In these applications, NPC requested to decrease rates by $116.3 million, a decrease of 5.04% while recovering $36 million of deferred fuel and purchased power costs. The going forward BTER became effective April 1, 2008. The PUCN issued its order in September 2008 setting the DEAA rate for all customers at $0.00 per kWh effective October 1, 2008. The PUCN found that NPC’s purchases of fuel and power were prudent and approved those costs for the test period.

BTER Update

In August 2008, NPC filed an update to its going forward BTER which increased rates $62.7 million, resulting in a 3% increase. The updated going forward BTER became effective October 1, 2008.

NPC Seventh Amendment to its 2006 IRP

In March 2008, NPC filed its seventh amendment to its 2006 IRP. Included in the amendment are several initiatives, all of which comport with the goal of providing clean, safe, and reliable electricity to NPC’s customers at reasonable and predictable prices. However, as a result of the potential acquisition of the Bighorn Power Plant, announced in April 2008, NPC resubmitted its seventh amendment to its IRP and filed an eighth amendment in May 2008. Significant requests that remained in the resubmitted seventh amendment include:

·	Approval to acquire a 50% interest in the Carson Lake Project.

·	Approval to construct the 6 MW (nominally rated) Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Gas Pipeline.

·	Approval of an updated load forecast.

On July 30, 2008, the PUCN approved the seventh amendment filing.

NPC Fifth Amendment to its 2006 IRP

In December 2007, NPC filed its fifth amendment to its 2006 IRP requesting approval of three items: 1) a revised Demand Side Management Plan; 2) a settlement agreement and new long-term power purchase agreement for approximately 50 MW of summer season capacity; and 3) a new long-term tolling agreement that will provide 570 MW of unit contingent summer season capacity. In March 2008, a stipulation between NPC and the intervening parties was accepted by the PUCN which recommended approval of the three items, as requested.

Sierra Pacific Power Company

SPPC Third Amendment to its 2007 IRP

In May 2008, SPPC filed a third amendment to its IRP along with NPC’s eighth amendment. As discussed above for NPC, the PUCN, in its order received October 2008, outlined certain minimum information regarding the EEC that shall be provided in SPPC’s amendment to its 2007 IRP, including but not limited to, an update of the engineering, construction and then current cost estimates for the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, an update of environmental costs and economic benefits attributed to the EEC and an update on the status of the all required permits. Additionally, modification of the in-service dates will be addressed in SPPC amendment to its 2007 IRP filing.

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SPPC Nevada Gas DEAA and BTER Update

In December 2007, SPPC filed for the authority to implement quarterly BTER adjustments for its natural gas and liquefied propane gas services. The authority was approved in January 2008, and as a result, in February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications SPPC requested to decrease rates by $9.9 million, a decrease of 5.53%, while refunding an over collection of $11.4 million in deferred natural gas and liquid propane costs. The going forward BTER became effective April 1, 2008. The PUCN issued its order in October 2008 setting the DEAA rate at $0.00 per therm effective October 1, 2008 and approving SPPC’s purchases of natural gas and propane for the test period as prudent.

SPPC Nevada Electric DEAA and BTER Update

In February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications SPPC requested to decrease rates by $42.1 million, a decrease of 4.57%, while refunding an over collection of $20.9 million in deferred fuel and purchased power costs. The going forward BTER became effective April 1, 2008. The PUCN issued its order in October 2008 setting the DEAA rate at $0.00 per kWh effective October 1, 2008. The PUCN found that SPPC’s purchases of fuel and power were prudent and approved those costs for the test period.

SPPC Nevada Gas BTER Update

In August 2008, SPPC filed an update to its going forward BTER which increased rates an additional $3 million, resulting in an additional 2% increase. The updated going forward BTER became effective October 1, 2008.

SPPC Nevada Electric BTER Update

In August 2008, SPPC filed an update to its going forward BTER which increased rates $18 million resulting in a 2% additional increase. The updated going forward BTER became effective October 1, 2008.

SPPC Second Amendment to its IRP

In March 2008, SPPC filed its second amendment to its 2007 IRP requesting approval to modify the schedule and development budget for the EEC in a manner consistent with the amendment to the NPC IRP described above, approval of a purchase power agreement, authority to fund CO2 research and approval of a revised load forecast. However, similar to NPC’s resubmission of its seventh amendment as discussed above, SPPC also resubmitted a second amendment to its 2007 IRP and filed a third amendment in May 2008. The requests that remained in the resubmitted second amendment were the approval of a purchase power agreement, authority to fund CO2 research and approval of a revised load forecast. The update of the EEC that was originally in the second amendment was included in the third amendment. On July 30, 2008, the PUCN approved the second amendment filing.

SPPC Nevada 2007 General Rate Case (GRC)

In December 2007, SPPC filed its statutorily required electric GRC. The filing requested a return on equity (ROE) and rate of return (ROR) of 11.5% and 8.73%, respectively, and an increase to general revenues of $110.8 million.

The PUCN issued its order in June 2008, with rates effective July 1, 2008. The PUCN order resulted in the following significant items:

·	Increase in general rates of $87.1 million, a 10.45% increase;

·	Return on equity (ROE) and rate of return (ROR) of 10.6% and 8.41%, respectively;

·	Authorization to recover the costs of the new Tracy 541 MW (nominally rated) combined cycle generating plant; and

·	Authorization to recover the projected operating and maintenance costs associated with the new Tracy combined cycle generating plant.

SPPC Nevada 2003 GRC

In its 2003 GRC, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project. SPPC's participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable.

In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. As a result, these amounts were expensed in 2004. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). On January 25, 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (“the Order”). On March 27, 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. On June 12, 2006, the District Court granted the PUCN’s motion to stay the Order. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and on January 18, 2007 the matter was remitted back to the District Court, which, consistent with the Order, remanded the matter back to the PUCN for further review.

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On March 18, 2008, the PUCN issued an order to place $5.8 million (Nevada jurisdiction) of the previously disallowed $43 million unreimbursed costs in a regulatory asset account without a carrying charge. As a result of this order and in accordance with SFAS 90, Accounting for Abandonments and Disallowances of Plant Costs, SPPC recognized approximately $4.3 million in income for the nine months ended September 30, 2008. The remaining difference of $1.5 million will be recognized over an approximate six year period. The time for any party to appeal the PUCN’s decision ended in June 2008 and no appeals were filed.

SPPC California Energy Cost Adjustment Clause

In April 2008, SPPC filed to decrease rates by $12.2 million, a decrease of 15.2%. The California Public Utilities Commission approved the filing in August 2008. The rates requested in this filing were effective September 1, 2008.

NOTE 4. LONG-TERM DEBT

As of September 30, 2008, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

	NPC			SPPC		SPR Holding Co. and Other Subs.		SPR Consolidated
2008	$	(119	)	$	539	$	-	$	420
2009		7,218			600		-		7,818
2010		8,004			-		-		8,004
2011		369,924			-		-		369,924
2012		136,448			100,000		63,670		300,118
		521,475			101,139		63,670		686,284
Thereafter		2,475,506			1,183,250		460,539		4,119,295
		2,996,981			1,284,389		524,209		4,805,579
Unamortized Premium(Discount) Amount		(13,124	)		9,617		800		(2,707	)
Total	$	2,983,857		$	1,294,006	$	525,009	$	4,802,872

The preceding table includes obligations related to capital lease obligations. The approximate $119 thousand credit for NPC in 2008 includes semi-annual capital lease payments, which were due and paid prior to September 30, 2008. Substantially all utility plant is subject to the liens of NPC’s and SPPC’s indentures under which their respective General and Refunding Mortgage securities are issued.

Financing Transactions

Sierra Pacific Resources

Debt Repurchase

In October 2008, SPR repurchased approximately $19 million of its 6.75% Senior Notes due 2017 from SPR’s cash on hand. As of October 31, 2008, the remaining balance on the 6.75% Senior Notes is $191.5 million.

Nevada Power Company

In October 2008, NPC borrowed approximately $466.4 million from its $600 million Revolving Credit Facility which was used along with cash on hand to fund the approximately $510 million acquisition of the Bighorn Generating Station. The Bighorn Generating Station is a 598 MW (nominally rated), natural gas fired combined cycle facility.

General and Refunding Mortgage Notes, Series S

In July 2008, NPC issued and sold $500 million of its 6.5% General and Refunding Mortgage Notes, Series S, due 2018 . The net proceeds of the issuance were used to repay $270 million of amounts outstanding under NPC’s revolving credit facility and for general corporate purposes.

Redemption Notice

On July 15, 2008, NPC provided a notice of redemption to the holders of all of its remaining 9.00% General and Refunding Mortgage Notes, Series G, for approximately $17.2 million. The notes were redeemed on August 15, 2008, at 104.50% of the stated principal amount, plus accrued interest to the date of redemption. NPC used available cash on hand to redeem these notes.

Conversion of Coconino County Pollution Control Refunding Revenue Bonds and Clark County Pollution Control Revenue Bonds

In July 2008, NPC converted the $13 million principal amount Coconino County, Arizona Pollution Control Refunding Revenue Bonds Series 2006B bonds, due 2039 and the $15 million principal amount Clark County Nevada Pollution Control Revenue Bonds, Series 2000B due 2009, (collectively, the “Bonds”) from auction rate securities to variable rate demand notes. The purpose of these conversions was to reduce interest costs and volatility associated with these Bonds. NPC purchased 100% of the Bonds on that date with proceeds from its revolving credit facility and available cash, and are the sole holder of the Bonds until such time as NPC determines to reoffer the Pollution Control Bonds to investors. The Bonds remain outstanding and have not been retired or cancelled. However, because NPC is the sole holder of the Bonds, for financial reporting purposes the investment in the Bonds and the indebtedness will be offset for presentation purposes.

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Sierra Pacific Power Company

Conversion of Humboldt County Pollution Control Refunding Revenue Bonds Series 2006

In October 2008, SPPC converted the $49.8 million principal amount, Humboldt County, Nevada Pollution Control Refunding Revenue Bonds Series 2006 bonds, due 2029 (the “Pollution Control Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Pollution Control Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Pollution Control Bonds until such time as SPPC determines to reoffer the Pollution Control Bonds to investors. The Pollution Control Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Pollution Control Bonds, for financial reporting purposes the investment in the Pollution Control Bonds and the indebtedness will be offset for presentation purposes.

General and Refunding Mortgage Notes, Series Q

On September 2, 2008, SPPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013. The net proceeds of the issuance were used to repay $238 million of amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Maturity of General and Refunding Mortgage Bonds, Series A

On June 2, 2008, the 8.00% General and Refunding Mortgage Bonds, Series A, in the aggregate principal amount of approximately $99.2 million, matured. SPPC paid for the maturing debt plus interest with the use of $90 million from its revolving credit facility, which was repaid with the proceeds of the Series Q offering, plus cash on hand.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In July 2008, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007B bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce the interest rate on these bonds. SPPC purchased 100% of the Water Bonds on that date, with proceeds from its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Pollution Control Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, because SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.

NOTE 5. DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC and NPC apply SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (“SFAS 133”), as amended by SFAS 138, SFAS No. 149, SFAS No. 155, and SFAS No. 157. As amended, SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It 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 meets certain defined conditions and qualifies as an effective hedge. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for by the Utilities under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value.

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Commodity Risk

The energy supply function encompasses the reliable and efficient operation of the Utilities’ generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. SPR’s and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

Adoption of SFAS 157

Effective January 1, 2008, SPR and the Utilities adopted SFAS 157, which defines fair value, establishes a framework for measuring fair value and enhances disclosures about assets and liabilities recorded at fair value.

SFAS 157 also establishes a three-level hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Derivative instruments used by SPR and the Utilities to manage energy price risk are valued using quoted exchange prices, external dealer prices and option pricing modules that utilize readily observable market parameters and are therefore classified within level 2 of the fair value hierarchy. The three levels are defined as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 – Unobservable inputs that are supported by little or no market activity and that are significant.

Determination of Fair Value

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps and options. Forwards and swaps are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Options are valued based on an income approach that uses an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option volatility rates. The determination of the fair value for its derivative instruments not only include counterparty risk, but also incorporate the impact of SPR and the Utilities nonperformance risk on its liabilities. Nonperformance risk is based on the credit quality of SPR and the Utilities and had no impact to the fair value of its derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of SPR, NPC and SPPC and the related regulatory assets/liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS 133. Due to deferred energy accounting treatment 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. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income (dollars in millions):

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	September 30, 2008 Fair Value Level 2									December 31, 2007 Fair Value
	SPR			NPC			SPPC			SPR			NPC			SPPC

Risk management assets- current	$	17.3		$	12.8		$	4.5		$	22.3		$	16.1		$	6.2
Risk management assets- noncurrent		8.9			6.5			2.4			12.5			9.1			3.4
Total risk management assets		26.2			19.3			6.9			34.8			25.2			9.6

Risk management liabilities- current		185.8			132.5			53.3			39.5			27.0			12.5
Risk management liabilities- noncurrent		35.2			22.6			12.6			7.4			5.1			2.3
Total risk management liabilities		221.0			155.1			65.9			46.9			32.1			14.8

Less prepaid electric and gas options		15.6			11.2			4.4			13.9			10.2			3.7

Risk management regulatory assets/liabilities – net (1)	$	(210.4	)	$	(147.0	)	$	(63.4	)	$	(26.0	)	$	(17.1	)	$	(8.9	)

(1) When amount is negative it represents a Risk Management Regulatory Asset (loss), when positive it represents a Risk Management Regulatory Liability (gain).

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities open derivative positions with its counterparties and the changes in forward commodity prices. The decrease in risk management assets as of September 30, 2008, as compared to December 31, 2007, is mainly due to unfavorable open derivative positions on natural gas options held by the Utilities to hedge energy price risk for their customers resulting from lower commodity prices for natural gas at September 30, 2008 relative to contract prices.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Reid Gardner Station

Surface and Groundwater Matters

Reid Gardner Station is a coal generating station consisting of four units. NPC is the owner and operator of Unit Nos. 1, 2 and 3. Unit No. 4 is co-owned by the California Department of Water Resources (CDWR) 67.8% and 32.2% by NPC. NPC is the operating agent for Unit No. 4.

Reid Gardner has a number of raw water and scrubber make-up storage ponds, as well as ponds used for process water evaporation and fly ash settling. Process water, which has been used beyond the treatable limits, is routed to onsite ponds for evaporation. Waste management units are present throughout the site and surrounding area. Environmental contaminants identified at Reid Gardner include but are not limited to, elevated concentrations of total dissolved solids, sulfate, chloride, dissolved metals, volatile organic compounds and petroleum hydrocarbons.

In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an Order that requires all evaporation and fly ash settling ponds to be closed or lined with impermeable liners over the next ten 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. Any future ponds will be double-lined with inter-liner leak detection in accordance with the most recent NDEP Authorization to Discharge Permit issued October 2005.

Pond construction and lining costs to satisfy the NDEP order expended through September 30, 2008 is approximately $45 million. No additional expenditures are projected through 2008.

In 2006 and 2007, the water division of NDEP has been in discussions with NPC regarding what additional surface and groundwater remediation may be required at the site, beyond the scope of the current pond relining project. The proposed solution was to enter into an Administrative Order on Consent (AOC) and the final form of the proposed AOC was delivered to NPC in December 2007. Until such time, NPC did not know the extent of the obligation or scope of work that would be required to effect site restoration due to the complexities associated with environmental remediation of the target media and the evolving standards of acceptable remediation standards. As a result, management was unable to reasonably estimate the cost of this comprehensive remediation project prior to concluding the negotiations and receiving the final AOC from the NDEP.

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In February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. The AOC has been designed to supersede previous Orders and takes a comprehensive approach to address historical environmental impacts associated with facility operations. Upon receiving the final document in December 2007, management was able to estimate a range of costs to satisfy the requirements of the AOC. As a result, NPC has recorded an asset retirement obligation of approximately $20 million, which it expects to receive regulatory recovery of, similar to the PUCN’s treatment of other asset retirement obligations. Other costs associated with the AOC are expected to include capital expenditures and remediation costs of approximately $32.3 million in addition to operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is initiated and additional characterization has been completed.

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. Management is continuing to evaluate various options including reclamation or sale of the property.

Litigation Contingencies

Nevada Power Company

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station (Navajo Station) which is located in Northern Arizona and is operated by the Salt River Project (Salt River). Other participants in the Navajo Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station (Mohave Station) which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.

Royalty Claim

On October 15, 2004, Navajo Station’s coal supplier, Peabody Western Coal Co. (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and SCE in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

As discussed in more detail in the 2007 Form 10-K, the Navajo Joint owners were first served in the Missouri lawsuit in January 2005. In July 2008, the Court dismissed the three counts against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Station and the Mohave Station. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both Navajo Station and the Mohave Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action had been stayed since October 5, 2004. In March, 2008, the US District Court lifted the stay and referred pending discovery related motions to a Magistrate judge. The Magistrate filed his Report and Recommendations on June 13, 2008 and the Navajo thereafter sought judicial review of the Magistrate’s Report and Recommendations by filing an Objection with the District Court on June 27, 2008. The parties are awaiting the Judge’s decision.

Retiree Health Care and Reclamation Claims

In addition to the above action before the Missouri State Court, Peabody further asserted in 1994 that the Navajo Joint Owners are liable under the Coal Supply Agreement (CSA) for Retiree Health Care Costs (RHCC) and Final Reclamation Costs (FRC), which Peabody WC is obligated to pay after the CSA expires and the Kayenta Mine closes. In 1996, Salt River and the Navajo Joint Owners filed a complaint in the Maricopa County (Arizona) Supreme Court seeking determinations that they are not liable for RHCC or FRC or, alternatively, that Peabody WC cannot recover RHCC and FRC until after the CSA ends. The case was dormant for several years, while Peabody WC pursued other RHCC and FRC claims arising out of similar coal contracts. Settlement discussions, led by Salt River on both the RHCC matter and the FRC claim reached final approvals with Peabody WC and the Navajo Joint Owners in July 2008 (Settlement Agreement and Mutual Release with Peabody). As of September 30, 2008, NPC has a $16.7 million liability recorded which management has assessed as the approximate amount to be paid, and recorded a corresponding other regulatory asset for such claims, as management believes that these costs are recoverable through deferred energy. The underlying lawsuit and arbitration have both been dismissed.

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Nevada Power Company and Sierra Pacific Power Company

Calpine Settlement

On September 19, 2007, NPC, SPPC and Calpine Corporation (“Calpine”) entered into a settlement agreement (the “Settlement Agreement”) that resolved the issues and claims pertaining to three proofs of claim (Claim Nos. 5177, 5178 and 5179) filed by the Utilities against Calpine in Calpine’s bankruptcy proceeding. The Settlement Agreement was approved by the United States Bankruptcy Court for the Southern District of New York on October 10, 2007, and by the Federal Energy Regulatory Commission (“FERC”) on December 28, 2007, in orders that are final and non-appealable.

Claim Nos. 5177 and 5179 filed by SPPC and NPC relate to complaints filed with FERC in December 2001 under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in reaction to the Western United States energy crisis. The Settlement Agreement provided that, for Claim Nos. 5177 and 5179, SPPC and NPC would receive general unsecured claims in the Calpine bankruptcy proceeding of approximately $1.7 million and $1.3 million respectively, totaling $3 million. In February 2008, Calpine distributed shares of Calpine common stock to SPPC and NPC with respect to Claim Nos. 5177 and 5179, at the approximate value at the time of the distribution of approximately $1.3 million, and $1.1 million, respectively. The Utilities recognized these amounts as income for the nine months ended September 30, 2008.

Claim No. 5178 filed by NPC regarding Calpine’s alleged breach of a 400 MW transmission service agreement (“TSA”) and a 2002 settlement agreement approved by the FERC. The Settlement Agreement provided that the claim shall be amended to reflect a general unsecured claim of $18 million against Calpine. NPC agreed to treat the distribution in respect to Claim No. 5178 as a prepayment for a new 400 MW TSA (“New TSA”) with a term commencing January 1, 2008 and ending approximately March 31, 2010, assuming no change in NPC’s open access transmission tariff (“OATT”) service schedules and, in the event of any such changes, ending on the date the $18 million is depleted based on the applicable OATT service rate schedule. In February 2008, Calpine distributed shares of Calpine common stock to NPC having an approximate value at that time of $14.4 million, which will be recognized as transmission revenue over the term of the new TSA.

The distributions discussed above represent approximately 80% of the balance owed to NPC and SPPC under the three proofs of claims filed. Management cannot predict if the remaining 20% will be recovered due to the status of Calpine’s bankruptcy proceedings, and as such has not recorded any further amounts as income. Subsequent to the distribution, NPC and SPPC sold all of their shares of Calpine common stock and recorded a gain of $1.8 million for the nine months ended September 30, 2008.

Sierra Pacific Power Company

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Under the terms of the contract with TMWA, SPPC is required to transfer the hydro assets in working condition, or, alternatively SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the Farad flume and Farad 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 for Farad Dam. The case went to trial before the Court in April 2008. On September 30, 2008, the Court ruled that SPPC was not time barred from reconstructing Farad Dam, and has coverage for the full rebuild costs, subject to coverage sub-limits set forth in the insurance policies. The Court further ruled that SPPC is entitled to recover $4 million for costs incurred to date on Farad Dam and that SPPC shall have three years to rebuild the dam from the date of the Court’s decision. In the event Farad Dam is not rebuilt, the court determined SPPC would be entitled to actual cash value of approximately $1.3 million; however, SPPC has requested the court to reconsider the cash value determination in its decision. The Insurers have 30 days from the Court’s decision on reconsideration of the Court’s judgment to file an appeal.

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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, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.

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

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan.

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

	Three months ended September 30,				Nine months ended September 30,
	2008		2007		2008		2007
Basic EPS
Numerator ($000)

Net income applicable to common stock	$	150,783	$	152,222	$	210,975	$	193,583

Denominator
Weighted average number of common shares outstanding		234,096,559		221,612,243		233,975,552		221,424,682

Per Share Amounts

Net income applicable to common stock	$	0.64	$	0.69	$	0.90	$	0.87

Diluted EPS
Numerator ($000)

Net income applicable to common stock	$	150,783	$	152,222	$	210,975	$	193,583

Denominator (1)
Weighted average number of shares outstanding before dilution		234,096,559		221,612,243		233,975,552		221,424,682
Stock options		26,738		73,834		48,340		124,013
Non-Employee Director stock plan		66,130		48,513		59,810		44,597
Employee stock purchase plan		-		-		290		2,630
Restricted Shares		11,804		-		6,121		-
Performance Shares		453,901		234,212		409,156		187,502
		234,655,132		221,968,802		234,499,269		221,783,424

Per Share Amounts

Net income applicable to common stock	$	0.64	$	0.69	$	0.90	$	0.87

(1)

The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the three and nine months ended September 30, 2008 and 2007, due to conversion prices being higher than market prices for all periods and are therefore anti-dilutive. Under the nonqualified stock option plan for the three and nine months ended September 30, 2008, 1,049,833 and 977,463 shares, respectively, would be included and 685,582 and 713,826 shares, respectively, would be included for the three and nine months ended September 30, 2007.

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NOTE 8. PENSION AND OTHER POSTRETIREMENT BENEFITS

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

Sierra Pacific Resources, consolidated

	For The Three Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	5,237		$	5,725		$	641		$	268
Interest cost		10,677			9,855			2,683			2,570
Expected return on plan assets		(11,463	)		(10,474	)		(2,088	)		(1,309	)
Amortization of prior service cost		(265	)		407			(257	)		30
Amortization of net (gain)/loss		1,980			1,803			872			242
Amortization of Transition Obligation		-			-			-			815

Net periodic benefit cost	$	6,166		$	7,316		$	1,851		$	2,616


	For The Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	16,506		$	17,175		$	1,922		$	1,804
Interest cost		32,142			29,565			8,049			7,711
Expected return on plan assets		(35,587	)		(31,422	)		(6,264	)		(3,927	)
Amortization of prior service cost		25			1,222			(771	)		91
Amortization of net (gain)/loss		4,733			5,409			2,617			2,444
Amortization of Transition Obligation		-			-			-			727

Net periodic benefit cost	$	17,819		$	21,949		$	5,553		$	8,850

Nevada Power Company

	For The Three Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	3,103		$	3,273		$	304		$	260
Interest cost		5,334			4,744			631			543
Expected return on plan assets		(5,496	)		(4,750	)		(675	)		(310	)
Amortization of prior service cost		(205	)		358			289			31
Amortization of net (gain)/loss		983			857			202			170
Amortization of Transition Obligation		-			-			-			242

Net periodic benefit cost	$	3,719		$	4,482		$	751		$	936

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	For The Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	9,715		$	9,819		$	912		$	779
Interest cost		15,944			14,233			1,893			1,628
Expected return on plan assets		(17,058	)		(14,250	)		(2,026	)		(929	)
Amortization of prior service cost		159			1,072			868			91
Amortization of net (gain)/loss		2,339			2,572			606			511
Amortization of Transition Obligation		-			-			-			727

Net periodic benefit cost	$	11,099		$	13,446		$	2,253		$	2,807

Sierra Pacific Power Company

	For The Three Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	1,940		$	2,138		$	319		$	380
Interest cost		5,045			4,775			2,013			1,548
Expected return on plan assets		(5,668	)		(5,492	)		(1,378	)		(745	)
Amortization of prior service cost		(62	)		53			(550	)		-
Amortization of net (gain)/loss		913			867			658			492

Net periodic benefit cost	$	2,168		$	2,341		$	1,062		$	1,675

	For The Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	6,058		$	6,415		$	956		$	1,368
Interest cost		15,194			14,324			6,041			5,569
Expected return on plan assets		(17,601	)		(16,476	)		(4,134	)		(2,683	)
Amortization of prior service cost		(74	)		159			(1,651	)		-
Amortization of net (gain)/loss		2,168			2,600			1,975			1,770

Net periodic benefit cost	$	5,745		$	7,022		$	3,187		$	6,024

SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” (SFAS 158) requires companies to eliminate the early measurement date and to measure their Defined Benefit Pension and Other Postretirement Plans consistent with their fiscal year end. SFAS 158 provided a transition alternative to the elimination of the early measurement date by allowing earlier measurements determined for year end reporting of the fiscal year immediately preceding the year that the measurement date provisions are applied to be used to calculate the additional expense. As such and in accordance with SFAS 158, the amounts below represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007. SPR, NPC and SPPC recorded additional pension and other postretirement benefits costs relating to the elimination of the early measurement date to beginning retained earnings, of $5.3 million and $1.0 million; $3.6 million and $0.6 million; and $1.4 million and $0.4 million, respectively, before taxes.

In November 2007, the Board of Directors approved a change in the defined benefit pension plan for SPR’s management, professional, administrative, and technical employees, from a final average pay formula to a cash balance formula. Employees with combined age and service totaling 75 years or more, have the choice of staying with the current plan or electing to switch to the new plan, which went into effect on April 1, 2008. Although these changes resulted in cost savings, the recent downturn in the equity and debt markets have caused a reduction in the asset values of the pension trust resulting in higher costs and liability values when the plan was re-measured in April 2008.

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As a result of the changes noted above, accrued retirement benefit obligations increased from December 31, 2007 for changes in the asset values of the pension trust and revisions to Other Post-Employment Benefits (“OPEB”) estimates, offset by a decrease in the obligation for changes in plan design associated with the cash balance formula. The net increase to accrued retirement obligations at September 30, 2008, was $57.8 million, $19.5 million and $34.8 million for SPR, NPC, and SPPC, respectively, with an offset to the Regulatory Asset for Pension Plans. Additionally, included in the net periodic benefit costs above for Pension Benefits are $990 thousand, $231 thousand and $803 thousand for SPR, NPC and SPPC, respectively, and for Other Postretirement Benefits $1.9 million, $367 thousand and $1.6 million for SPR, NPC and SPPC, respectively, as a result of the changes noted above.

In the third quarter ended September 30, the company made contributions to the pension plan and the other postretirement benefits plan in the amount of $22 million and $8 million, respectively. At the present time, there is not expected to be any further contributions to either plan in 2008.

NOTE 9. DIVIDENDS

On February 7, 2008, SPR’s Board of Directors declared a quarterly cash dividen d of $0.08 per share which was paid on March 12, 2008, to common shareholders of record on February 22, 2008. On April 28, 2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share, to common shareholders of record on May 23, 2008 which was paid on June 11, 2008. On August 4 , 2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share to common shareholders of record on August 22, 2008, which was paid on September 10, 2008. On October 30, 2008, SPR Board of Directors declared a quarterly cash dividend of $0.10 per share to common shareholders of record on December 2, 2008 to be paid on December 17, 2008.

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

RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of Sierra Pacific Resources (SPR), Nevada Power Company (NPC), or Sierra Pacific Power Company (SPPC) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)

economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, customer bankruptcies, weaker housing markets and a decrease in tourism, particularly in Southern Nevada, which could affect customer collections, customer demand and usage patterns;

(2)	changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, including the effect of weaker housing markets, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)

the ability and terms upon which SPR, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of: continued volatility in the global credit markets, unfavorable rulings by the Public Utilities Commission of Nevada (PUCN), untimely regulatory approval for utility financings, and/or a downgrade of the current debt ratings of SPR, NPC, or SPPC;

(4)

financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability and cost of capital, or interest rate fluctuations resulting from, among other things, the credit quality of bond insurers that guarantee certain series of the Utilities’ auction rate tax-exempt securities;

(5)	changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

(6)

unseasonable weather, drought and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability to procure adequate supplies of fuel or purchased power and the cost of procuring such supplies, and could affect the amount of water available for electric generating plants in the Southwestern United States;

(7)

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

(8)	changes in environmental laws or regulations, including the imposition of limits on emissions of carbon dioxide from electric generating facilities, which could significantly affect our existing operations as well as our construction program, especially the proposed Ely Energy Center;

(9)

construction risks, such as delays in permitting, changes in environmental laws, difficulty in securing adequate skilled labor, cost and availability of materials and equipment (including escalating costs for materials, labor and environmental compliance due to timing delays and other economic factors which may affect vendor access to capital), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(10)	whether the Utilities can procure sufficient renewable energy sources in each compliance year to satisfy the Nevada Portfolio Standard;

(11)

unfavorable or untimely rulings in rate cases filed or 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 costs recorded by SPPC for its gas distribution business;

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(12)

wholesale market conditions, including availability of power on the spot market and the availability to enter into gas financial hedges with creditworthy counterparties, 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;

(13)	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;

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

(15)	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;

(16)

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 gaming establishments in California, other states and internationally;

(17)	employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages; and

(18)	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

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.

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EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of 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 (holding company) and the Utilities collectively).

In September 2008, SPR announced that NPC and SPPC will do business under the name NV Energy.

SPR also announced that it will seek shareholders' approval to amend its corporate charter to change its corporate name from Sierra Pacific Resources to NV Energy, Inc. subject to shareholders' approval at a special meeting called for November 19, 2008. SPR would assume the new name at the time of such approval.

The name change for NPC and SPPC unifies under a single brand a company that serves Nevada’s energy needs from north to south. However, for purposes of financial reporting, rate filings, and contractual transactions, the corporate legal structures of SPR and the Utilities remains unchanged and will continue to be referred to as SPR, NPC, and SPPC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations consists primarily of the following:

▪ Results of Operations

▪ Analysis of Cash Flows

▪ Liquidity and Capital Resources

▪ Energy Supply (Utilities)

▪ Regulatory Proceedings (Utilities)

SPR’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas. Other segment operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of SPR and account for substantially all of SPR’s assets and revenues. SPR, NPC and SPPC are separate filers for SEC reporting purposes, and as such, this discussion has been divided to reflect the individual filers (SPR, NPC and SPPC), except for discussions that relate to all three entities or to both Utilities.

For the three months ended September 30, 2008, SPR recognized net income applicable to common stock of $150.8 million compared to $152.2 million for the same period in 2007. For the nine months ended September 30, 2008, SPR recognized net income applicable to common stock of $211.0 million compared to $194.0 million for the same period in 2007. See SPR’s, NPC’s and SPPC’s respective Results of Operations for more details on the change in earnings.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. 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 typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage by the Utilities’ customers due to varying weather and other energy usage patterns necessitate a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2008 and Beyond Outlook

In Southern Nevada, population growth continues, however at a much slower pace than in prior years. As a result of economic conditions both regionally and nationally, Southern Nevada has experienced decreased activity in the real estate, construction and tourism markets. Additionally, the recent credit and capital markets crisis will likely impact Nevada’s economy as major commercial and residential developments are delayed or potentially halted due to the inability to obtain or the high cost of credit and/or capital. However, in Clark County, an increase of 25,000 hotel rooms is expected by 2010, and NPC’s load forecast projects growth of approximately 1% and 4% for the years 2009 and 2010, respectively. The recent volatility in the global credit and financial markets has created an unprecedented level of uncertainty regarding future business conditions. As a result, our management is continually focusing on and reevaluating our assessments, strategies and projections for factors such as customer growth, load forecasts, capital expenditures, rising fuel costs, access to capital markets, collections on accounts receivable and counterparty risk among other factors. While management expects to maintain this process of continual reevaluation for the foreseeable future, it is not possible to predict how long current market volatility will continue or what its long-term effect will be on the economy in general or on our financial position or results of operations in particular.

Despite current economic conditions, long-term energy needs continue to increase in the Western and Southwestern portions of the United States. At the same time, however, the development of generating facilities by utility companies has decreased. As a result, the cost of energy and natural gas continues to change with increased demand and the decline in the ability to meet those demands. The economics of this situation coupled with variations in weather, the capabilities and limits on the Utilities, owned generating facilities, transmission constraints, regulations, and changes and potential changes in environmental laws are significant business issues for the Utilities. As a result, the Utilities’ strategies, as evidenced by their most recent amendments to their Integrated Resource Plans (IRP), are aimed at reducing dependence on purchased power by the use of energy efficiency and conservation programs and diversifying fuel mix, including renewable energy and owning more generating facilities.

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2008 Key Objectives

·	Management of Energy Resources

o	Energy Efficiency and Conservation Programs

o	Purchase and Development of Renewable Energy Projects

o	Construction of Generating Facilities

o	Management of Energy Risk, including fuel and purchased power costs

·	Management of Environmental Matters

·	Management of Regulatory Filings

·	Further Broaden Access to Capital

Management of Energy Resources

Energy Management encompasses energy efficiency and conservation programs, diversification of fuel mix, optimization of generation assets, management of energy risk which includes the purchase of short term and long term supply contracts, transmission, storage, reliability and efficiency, and regulatory and legal considerations. The ability to balance and optimize these functions is a significant business challenge that we face.

Energy Efficiency and Conservation Programs

A part of our strategy to reduce dependence on purchased power is to manage our resources against our load requirements with energy efficiency and conservation programs. As such, the Utilities’ have committed to spending approximately $135 million from 2008-2010 towards increasing efficiency and qualified conservation programs. NPC and SPPC have received PUCN approval of approximately $110.5 million and $29.8 million, respectively for the years 2008-2010, which will be deferred as a regulatory asset subject to prudency review by the PUCN. The PUCN approval of the demand-side management (“DSM”) budget increase was a key step in expanding the energy savings yield from the DSM programs.

NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public, and low income). After the DSM percentage allowance, as described below, is fully utilized, NPC’s and SPPC’s strategy is to continue to implement cost-effective DSM programs.

Furthermore, the Portfolio Standard, discussed below, allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. A portfolio energy credit is created for each kWh of energy conserved by qualified energy efficiency programs. Energy saved during peak demand hours earns double the portfolio energy credits. In October 2008, the PUCN accepted the Utilities Portfolio Standard Annual Report for Compliance Year 2007 (the “Portfolio Report”). In the Portfolio Report, the Utilities reported that through energy efficiency measures they achieved 60% of the allowable 25% that may be used to meet the Portfolio Standard. In addition, NPC reported that it is in a position to achieve the maximum 25% in 2008.

Purchase and Development of Renewable Energy Projects

The Utilities have embarked on a strategy to invest in renewable energy that, along with purchased power contracts and an increase in DSM programs, will enhance the opportunity for the Utilities to fully meet the renewable energy portfolio standard (Portfolio Standard) as required by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewable energy resources. NPC’s current capital budget includes investing approximately $355 million for renewable energy projects through 2012.

Nevada law sets forth the Portfolio Standard, requiring providers of electric service to acquire, generate, or save a specific percentage of its total retail energy sales from renewable energy resources (Renewables). Renewables include biomass, geothermal, solar, waterpower and wind projects. In 2008, the Utilities are required to obtain 9% of their total energy from Renewables. The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015. Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources.

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Nevada law requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In the Utilities’ Portfolio Report NPC reported that with PUCN approval of a sale and purchase of SPPC’s excess non-solar portfolio credits (PCs), NPC met the non-solar Portfolio Standard. SPPC reported compliance with the non-solar component of the Portfolio Standard. However, due to the late commercial operation of planned solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard. Additionally, the report described the Utilities ongoing activities to reach full compliance with the Portfolio Standard in the near future.

The PUCN issued its Order accepting the Utilities’ Portfolio Standard Annual Report for Compliance Year 2007 and accepted a stipulation that granted an exemption from meeting the Portfolio Standard. In addition, because the Utilities took reasonable efforts to comply with the Portfolio Standard the PUCN waived any administrative fines or penalties for non-compliance.

In May 2008, NPC re-filed its 7th amendment to its 2007-2026 Integrated Resource Plan with the PUCN (“2006 Resource Plan”). Included in the amendment are renewable energy requests which seek approvals to acquire a 50% interest in a minimum 30 MW geothermal project (“Carson Lake Project”) and to construct a 6 MW Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Pipeline. In July 2008, the PUCN approved the 7th amendment. Both projects are scheduled for commercial operation in late 2010. In August 2008, NPC filed its ninth amendment to its IRP. In the amendment NPC seeks approval to establish a regulatory asset for the Carson Lake Project and related operating and maintenance costs, depreciation and return on the plant, until such time it is included in general rates.

Construction of Generating Facilities

Ely Energy Center

As discussed in more detail in the 2007 Form 10-K, included in the Utilities’ IRP and various amendments is the construction of the Ely Energy Center that consists of two 750 MW coal generation units to be located near Ely, Nevada and a 250-mile 500 kilovolt (kV) transmission line that would deliver electricity from the Ely Energy Center and from any possible future renewable resource projects in the area, as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state. In May 2008, the Utilities filed amendments to their IRP’s. Among other items, the Utilities requested permission to file the required IRP amendment regarding final approval of the Ely Energy Center in April 2010, after the issuance of required permits and bids for equipment and engineering, procurement and construction costs are obtained. This request would give the Utilities a better opportunity to evaluate the feasibility of the Ely Energy Center for factors such as, but not limited to, the effects of construction costs, carbon dioxide and climate change legislation, commodity prices and electricity demand in Nevada. However, in October 2008, the PUCN ruled certain information regarding the Ely Energy Center and other alternatives shall be provided in NPC’s 2009 IRP filing and SPPC’s corresponding amendment to its 2007 IRP.

Natural Gas Generating Units

In 2006, SPPC began construction of a 541 MW gas fired high efficiency combined cycle generator at the Tracy Plant, which was completed in July 2008. In 2007, NPC began the construction of 619 MWs of natural gas-fired combustion turbine peaking units at Clark Station. The first block of approximately 206 MWs became commercially operable in July 2008 and the remaining two blocks are expected to be completed by the end of the fourth quarter of 2008. Additionally, in 2007, NPC began construction of a 500 MW natural gas generating station at the existing Harry Allen Station which is expected to be operational by summer 2011.

In October 2008, NPC purchased a 598 MW (nominally rated), natural gas fired combined cycle power plant, the Bighorn Power Plant (“Bighorn”), from Reliant Resources, Inc., for approximately $510 million, including costs for inventory and other closing costs and adjustments. In NPC’s 8th amendment to its IRP, the PUCN approved the purchase of Bighorn and NPC will include the acquisition costs in its General Rate Case to be filed in December 2008. Also approved by the PUCN in NPC’s 8th amendment to its IRP is the construction of the Harry Allen Station discussed above, and the approval to include the construction costs in rate base which allows NPC to earn a return on its investment prior to the time the plant becomes operational.

Management of Energy Risk

For the remainder of 2008 and for the future, the Utilities have open positions resulting from the management of their portfolio of generation resources, load obligations, and purchased power and fuel contracts, due to unfolding developments in regional energy markets. The risks associated with the open positions are addressed in various ways. The Utilities implement a prudent strategy of piecemeal procurements transacted in regular intervals and completed before the start of the peak summer season. This provides the Utilities with ample opportunities for optimizing their portfolio on a rolling basis in anticipation of changes in system conditions, load forecasts, and regional energy market fundamentals. The Utilities also coordinate the planned maintenance schedules of their owned generating plants and transmission facilities with expectations of start dates of new generating plants or purchased power contracts. In addition, in 2008 the Utilities received PUCN approval to implement a longer term sales program for non-peaking months. The longer term sales program will allow the Utilities to sell their excess energy during non peak months on the open market.

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Management of Environmental Matters

The impact environmental laws can have on existing generating facilities and current and prospective capital construction projects include but are not limited to increased costs, closure of existing facilities, mandated equipment upgrades, and termination of the construction of facilities. Environmental laws already affect the energy we buy as discussed above under Purchase and Development of Renewable Energy Projects . For the remainder of 2008 and the next four years, NPC is projected to spend approximately $126.0 million on certain major environmental projects/upgrades. Additionally, as discussed above, under Construction of Generating Facilities, Ely Energy Center , environmental laws will play a significant role in the construction of Ely Energy Center.

A key objective for the Utilities in 2008 will be to enhance and maintain our energy infrastructure investments in ways that meet customer demand for reliable energy in an efficient and environmentally responsible manner. The Utilities believe that a diverse and balanced portfolio of energy resources represents opportunity for reliability and cost control, yet are also mindful of our overriding environmental responsibility. The Utilities are committed to making technology choices with a primary focus on limiting emissions and optimizing our investments so that prices remain competitive. To meet the growing demand for power, the Utilities are investing in a new generation of highly efficient and environmentally advanced power plants, both coal and natural gas fired as well as adding new environmental controls to their existing plants. To help manage load demand, the Utilities are also increasing their participation and development of new energy efficiency and demand side conservation programs.

Management of Regulatory Filings

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for quarterly rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every three years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. Furthermore, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement. Resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases. The Utilities incur costs for such items as deferred fuel and purchased power costs, operations and maintenance and capital projects; however, costs are not recovered through rates until approved by regulators. The timing between costs incurred and recovery is considered regulatory lag. As such, timely and accurate filings of these various rate cases is essential to the Utilities’ operating and financial performance as it reduces regulatory lag, which has a direct effect on the cash flows of the Utilities. Furthermore, the timing of the filings/decisions can affect the timing of construction and thus the economic benefits. As a result, the Utilities file quarterly BTER updates to minimize exposure to changes in fuel and purchased power expense, file amendments to IRP’s as changes in resource needs occur, and under their general rate case, pursuant to recent Nevada law, may elect to include in their filing future projected costs particularly in the case of major construction projects and related operating and maintenance expense, where significant amounts of capital are required to reduce regulatory lag.

Significant decisions or filings in 2008 include, but are not limited to, SPPC’s 2007 GRC, amendments to the Utilities’ IRPs, and the filing of NPC’s GRC in late 2008. See Note 3, Regulatory Actions of the Condensed Notes to Financial Statements in this Form 10-Q.

Further Broaden Access to Capital

In 2008, the Utilities have generated sufficient cash from operations to meet their operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs. Additionally, the Utilities have utililized their revolving credit facilities and issued sufficient amounts of debt to fund construction projects and the acquisition of Bighorn. However significant amounts of capital may be necessary to fund existing and prospective construction projects, as well as volatile energy costs. In response, in October 2008, NPC filed a financing application with the PUCN to increase and diversify our access to liquidity. Furthermore, the recent credit and capital markets crisis has significantly tightened the availability of credit to many companies and increased the cost of borrowing generally. As a result, SPR and the Utilities will continue to evaluate alternative access to capital.

As a result of economic conditions discussed earlier, the acquisition of Bighorn and the timing of certain projects, management reduced the Utilities’ 2008 through 2012 estimated cash construction requirement from that reported in the 2007 Form 10K. The Utilities have reduced 2008 cash construction requirements by approximately $200 million. Management currently estimates cash construction expenditures for the remainder of 2008 through 2012 to be approximately $5.5 billion. Some of the major capital projects include the Ely Energy Center for $2.2 billion, Harry Allen for $631 million, renewable development for $355 million and environmental upgrades for $126 million. Of these major projects approximately $1.0 billion has been approved by the PUCN. Management is likely to meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and the issuance of equity by SPR. If energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, the Utilities may need to rely more on their revolving credit facilities, and if necessary, issue additional debt to support their operating costs or delay capital expenditures.

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SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Consolidated)

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $31.3 million and $31.9 million of interest costs for the nine months ended September 30, 2008 and 2007, respectively.

During the three months ended September 30, 2008, SPR recognized net income applicable to common stock of approximately $150.8 million compared to $152.2 million for the same period in 2007. The change was primarily due to an increase in interest on long term debt and a decrease in AFUDC.

During the nine months ended September 30, 2008, SPR recognized net income applicable to common stock of approximately $211.0 million compared to $193.6 million for the same period in 2007. The increase to net income applicable to common stock was primarily due to an increase in operating income as a result of NPC’s Base Tariff General Rates (BTGR), as a result of NPC’s 2006 GRC effective June 1, 2007 and SPPC’s 2007 GRC effective July 1, 2008 and an increase to AFUDC. These increases were partially offset by higher interest charges on long term debt and income recognized in 2007 for approximately $7.2 million (net of taxes) as a result of the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case, see Note 3, Regulatory Actions in the Notes to Financial Statements in the 2007 Form 10-K.

As of September 30, 2008, NPC had paid $54.9 million in dividends to SPR and SPPC had paid $78.3 million in dividends to SPR. On October 30, 2008, SPPC declared an additional $160 million dividend to SPR.

ANALYSIS OF CASH FLOWS

Cash flows increased during the nine months ended September 30, 2008 compared to the same period in 2007 due to an increase in from financing activities and a decrease in cash used by investing activities, partially offset by a decrease in cash from operating activities.

Cash From Operating Activities . The decrease in cash from operating activities was primarily due to increases in energy costs in excess of the energy revenue collected in rates, expenditures for conservation programs, site studies and other regulatory activities in 2008. The decrease was partially offset by the settlement with Calpine, prepaid transmission revenues and a reduction in funding for retirement plans.

Cash Used By Investing Activities . Cash used for investing activities decreased primarily due to the closing stages of major construction activity for the peaking units at Clark Station and the combined cycle natural gas power plant at the Tracy Generating Station which began in 2007 and 2006, respectively.

Cash From Financing Activities . Cash from financing activities increased primarily due to the issuance of NPC’s $500 million of 6.5% General and Refunding Mortgage Notes, Series S, due 2018, SPPC’s $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 offset partially by debt redemption and higher dividend payments to SPR shareholders in 2008.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Overall Liquidity

SPR’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of September 30, 2008 (in millions)
	SPR		NPC		SPPC
Cash and Cash Equivalents	$	229.1	$	177.7	$	29.3
Balance available on Revolving Credit Facility 1,2		N/A		585.4		313.2
	$	229.1	$	763.1	$	342.5

1. NPC’s and SPPC’s available balance reflects management's estimate of a reduction of approximately $11.0 million and $18.0 million, respectively, as a result of the

bankruptcy of a lending bank.

2. As of November 4, 2008, NPC and SPPC had approximately $232.2 million and $266.1 million available under their revolving credit facilities.

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SPR and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as United States treasury bills. In addition to cash on hand and the Utilities’ revolving credit facilities, the Utilities may issue debt up to $665 million on a consolidated basis, subject to certain limitations discussed below and in the Utilities’ respective sections, to meet their respective financial obligations.

SPR and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities. To manage liquidity needs as a result of seasonal peaks in fuel requirements, SPR and the Utilities may use hedging activities. In order to fund long-term capital requirements, SPR and the Utilities will likely meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and capital contributions from SPR from the issuance of equity by SPR. In October 2008, NPC borrowed approximately $466.4 million from its revolving credit facility, along with cash on hand, to fund the approximately $510 million acquisition of the Bighorn Generating Facility from Reliant Resources. NPC's management regularly evaluates whether NPC needs to increase its revolving credit facility. However, as discussed earlier in the executive overview, the Utilities have reduced their capital expenditures for the remainder of 2008 and for 2009 as a result of current economic conditions.

SPR has approximately $40.7 million payable of debt service obligations for 2008, of which $38.3 million was paid in the nine months ended September 30, 2008. SPR intends to pay the remaining interest payments through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below).

During the nine months ended September 30, 2008, there were no material changes to contractual obligations as set forth in SPR’s 2007 Form 10-K for SPR. See NPC’s and SPPC’s respective sections for changes in contractual obligations.

Financing Transactions

Debt Repurchase

Factors Affecting Liquidity

Effect of Holding Company Structure

As of September 30, 2008, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $210.5 million of its unsecured 6.75% Senior Notes due 2017; and $250 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, SPR’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. 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 and guarantee holders.

As of September 30, 2008, SPR, NPC, SPPC and their subsidiaries had approximately $4.8 billion of debt and other obligations outstanding, consisting of approximately $3.0 billion of debt at NPC, approximately $1.3 billion of debt at SPPC and approximately $524 million of debt at the holding company and other subsidiaries. Although SPR and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, SPR and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

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 financing 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. However, as a result of the recent credit rating upgrade of the Utilities’ secured debt to investment grade by Standard and Poor’s (S&P), these restrictions are suspended and will no longer be in effect so long as the debt remains investment grade by both Moody’s and S&P. See Credit Ratings below.

In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from earnings, or in the absence of earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

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Credit Ratings

SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations (NRSRO’s): Dominion Bond Rating Service (DBRS), Fitch Ratings Ltd. (Fitch), Moody’s Investors Service, Inc. (Moody’s) and S&P. The secured debt of NPC and SPPC is rated investment grade by all four rating organizations. As of October 31, 2008 , the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPR	Sr. Unsecured Debt	BB (low)	BB-	Ba3	BB
NPC	Sr. Secured Debt	BBB (low)	BBB-	Baa3	BBB
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	BB+
SPPC	Sr. Secured Debt	BBB (low)	BBB-	Baa3	BBB

On May 15, 2008, S&P increased SPR’s corporate credit rating to BB from BB-, and unsecured notes at SPR were raised to BB from BB-. At the same time, the secured ratings at NPC and SPPC were raised to BBB from BB+, and unsecured notes at NPC were raised to BB+ from BB. As a result of these upgrades, all four rating agencies currently rate the Utilities’ senior secured debt investment grade. S&P’s, Moody’s and DBRS’s rating outlook for SPR, NPC and SPPC is Stable. Fitch’s rating outlook for SPR, NPC and SPPC is Positive.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Credit Ratings of Bond Insurers

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and downgrades of bond insurers, among other negative matters. The interest rates on certain issues of the Utilities’ auction rate securities of approximately $488 million as of September 30, 2008, are periodically reset through auction processes. These securities are supported by bond insurance policies provided by either Ambac Financial Group (AMBAC), Financial Guaranty Insurance Company (FGIC), or MBIA, Inc. (MBIA) (collectively, the “Insurers”), and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. S&P’s and Moody’s ratings on these bonds are the higher of a bond issue's underlying rating and the Insurer's rating. As of September 30, 2008, AMBAC’s and MBIA’s credit ratings were investment grade or above. However, FGIC’s credit ratings were below investment grade. As a result, the bonds insured by FGIC are currently rated at the investment grade ratings of the Utilities’ secured debt. See Credit Ratings above . The uncertainty with the Insurers' credit quality has had an impact on the Utilities’ interest costs for the first nine months of 2008. With the ongoing review of the credit ratings of the Insurers, the Utilities are experiencing higher interest costs for these securities.

In July and October 2008, NPC and SPPC converted portions of their auction rate securities to variable rate demand notes. This conversion will likely result in higher interest charges compared to prior year, but lower than the failed auction rates for this tax exempt debt. See Financing Transactions in NPC’s and SPPC’s Liquidity sections. If higher interest rates continue on the remaining auction rate securities outstanding, the Utilities may seek to convert the debt to other short-term variable rate structures, term-put structures and/or fixed-rate structures.

Financial Covenants

Nevada Power Company and Sierra Pacific Power Company

Each of NPC's $600 million Second Amended and Restated Revolving Credit Agreement and SPPC's $350 million Amended and Restated Revolving Credit Agreement, dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires the Utility to 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 the Utility to 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, 2008 both Utilities were in compliance with these covenants.

Ability to Issue Debt

Certain debt of SPR places restrictions on debt incurrence, liens and dividends, 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 to 1. Under this covenant restriction, as of September 30, 2008, SPR would be allowed to incur up to $665 million of additional indebtedness on a consolidated basis.

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Notwithstanding this restriction, under the terms of the debt, SPR would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the two Utilities’ integrated resource plans. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

If the applicable series of SPR’s debt is 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 by both Moody’s and S&P (see Credit Ratings above).

Nevada Power Company

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements, and the terms of certain SPR debt. As of September 30, 2008, NPC had approximately $1.1 billion of PUCN financing authority. On October 20, 2008, NPC filed a financing application with the PUCN, requesting approximately $1.25 billion of additional long-term financing authority.

So long as NPC’s debt containing financial covenants remains investment grade by both Moody’s and S&P, the restrictions contained in those debt agreements are suspended. However, NPC is limited by SPR’s cap on additional consolidated indebtedness of $665 million. Notwithstanding this restriction under the terms of SPR’s debt, in addition to this amount, NPC would also be permitted to incur debt, including, but not limited to obligations incurred to finance property construction or improvements, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to its integrated resource plan. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $665 million, depending on the Utilities combined usage of their revolving credit facilities at the time of the covenant calculations.

Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s General and Refunding Mortgage Indenture (“Indenture”).

As of September 30, 2008, $3.3 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue an additional $536 million of General and Refunding Mortgage Securities as of September 30, 2008.

NPC also has the ability to release property from the lien of the mortgage indenture 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. See the 2007 Form 10-K for additional information.

Sierra Pacific Power Company

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements, and the terms of certain SPR debt. As of September 30, 2008, SPPC had approximately $495 million of PUCN financing authority.

So long as SPPC’s debt containing financial covenants remains investment grade by both Moody’s and S&P, the restrictions contained in those debt agreements are suspended. However, SPPC is limited by SPR’s cap on additional consolidated indebtedness of $665 million. Notwithstanding this restriction under the terms of SPR’s debt, in addition to this amount, SPPC would also be permitted to incur debt, including, but not limited to obligations incurred to finance property construction or improvements, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to its integrated resource plan. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s General and Refunding Mortgage Indenture (“Indenture”).

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As of September 30, 2008, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue an additional $539 million of General and Refunding Mortgage Securities as of September 30, 2008.

SPPC also has the ability to release property from the lien of the mortgage indenture 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 securities issuable under that indenture. See the 2007 Form 10-K for additional information.

Cross Default Provisions

None of the Utilities’ financing agreements contains 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.

Pension Plans

Due to recent market conditions and the decline in the fair value of pension plan assets, the funding status of our pension plan in 2009 is likely to deteriorate as compared to 2008. The final determination of pension plan contributions for 2009 and future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We believe that we have adequate liquidity to meet our pension plan funding obligations for 2009.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $124.3 million during the three months ended September 30, 2008 compared to net income of $133.1 million for the same period in 2007. During the nine months ended September 30, 2008, NPC recognized net income of approximately $165.5 million compared to net income of approximately $161.3 million for the same period in 2007.

During the nine months ended September 30, 2008, NPC paid $54.9 million in dividends to SPR.

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, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of NPC. For reconciliation to operating income, see Note 2, Segment information in the Condensed Notes to Financial Statements. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended September 30,								Nine Months Ended September 30,
						Change from								Change from
	2008			2007		Prior Year %			2008			2007		Prior Year %
Operating Revenues:
Electric	$	826,825		$	894,226		-7.5	%	$	1,866,220		$	1,887,499		-1.1	%


Energy Costs:
Purchased power		319,324			313,487		1.9	%		577,161			584,797		-1.3	%
Fuel for power generation		240,027			166,284		44.3	%		613,968			471,142		30.3	%
Deferral of energy costs-net		(80,191	)		54,868		-246.2	%		(44,107	)		149,531		-129.5	%
	$	479,160		$	534,639		-10.4	%	$	1,147,022		$	1,205,470		-4.8	%


Gross Margin	$	347,665		$	359,587		-3.3	%	$	719,198		$	682,029		5.4	%

Gross margin decreased for the three months ended September 30, 2008 compared to the same period in 2007 primarily due to a decrease in customer usage due to cooler weather and a change in customer usage patterns, partially offset by an increase in customer growth. Gross margin increased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in Base Tariff General Rates (BTGR) as a result of NPC’s 2006 GRC, effective June 1, 2007 and increased customer growth, partially offsetting these increases was a decrease in customer usage primarily due to cooler weather.

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

Electric Operating Revenue

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %
Electric Operating Revenues:
Residential	$	435,986	$	475,201		-8.3	%	$	887,173	$	921,510		-3.7	%
Commercial		134,391		147,821		-9.1	%		362,850		365,854		-0.8	%
Industrial		228,141		242,963		-6.1	%		537,930		535,309		0.5	%
Retail revenues		798,518		865,985		-7.8	%		1,787,953		1,822,673		-1.9	%
Other		28,307		28,241		0.2	%		78,267		64,826		20.7	%
Total Revenues	$	826,825	$	894,226		-7.5	%	$	1,866,220	$	1,887,499		-1.1	%

Retail sales in thousands
Of megawatt-hours (MWh)		7,413		7,502		-1.2	%		16,952		17,283		-1.9	%

Average retail revenue per MWh	$	107.72	$	115.43		-6.7	%	$	105.47	$	105.46		0.0	%

NPC’s retail revenues decreased for the three and nine months ended September 30, 2008 as compared to the same period in 2007 due to decreases in retail rates and decreases in customer usage due to cooler summer weather and changes in customer usage patterns. Retail rates decreased as a result of NPC’s various Base Tariff Energy Rate (BTER) quarterly cases (see Note 3, Regulatory Actions in the condensed Notes to the Financial Statements). Average residential, commercial, and industrial customers increased by 0.4%, 2.5% and 4.6%, respectively for the three months ended September 30, 2008. Average residential, commercial, and industrial customers increased by 0.9%, 2.9% and 3.9%, respectively for the nine months ended September 30, 2008.

Electric Operating Revenues – Other was comparable for the three months ended September 30, 2008 compared to the same period in 2007.

Electric Operating Revenues – Other increased for the nine months ended September 30, 2008, compared to the same period in 2007. The increase is primarily due to the elimination of the reclassification of revenues associated with Mohave, as a result of NPC’s 2006 GRC, which in 2007 were reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on Mohave refer to Note 1, Summary of Significant Accounting Policies in the Notes to Financial Statements in the 2007 Form 10-K. Also contributing to the increase was transmission related revenue as a result of the Calpine settlement, as discussed further in Note 5, Commitments and Contingencies.

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Energy Costs

Energy Costs include Purchased Power and Fuel for Generation. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of purchased power versus fuel for generation to meet demand can vary significantly. Factors that may affect energy costs include, but are not limited to:

Weather

·	Generation efficiency

·	Plant outages

·	Total system demand

·	Resource constraints

·	Transmission constraints

·	Natural gas constraints

·	Long term contracts; and

·	Mandated power purchases

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Energy Costs	$	559,351	$	479,771		16.6	%	$	1,191,129	$	1,055,939		12.8	%
Total System Demand		7,723		7,841		-1.5	%		17,872		18,327		-2.5	%
Average cost per MWh	$	72.43	$	61.19		18.4	%	$	66.65	$	57.62		15.7	%

For the three and nine months ended September 30, 2008, energy costs and the average cost per MWh increased primarily due to higher natural gas prices. Total system demand decreased primarily due to a decrease in customer usage as a result of cooler weather and a change in customer usage patterns.

Purchased Power

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Purchased Power	$	319,324	$	313,487		1.9	%	$	577,161	$	584,797		-1.3	%

Purchased Power in thousands
of MWhs		3,406		3,648		-6.6	%		6,435		7,200		-10.6	%
Average cost per MWh of
purchased power	$	93.75	$	85.93		9.1	%	$	89.69	$	81.22		10.4	%

Purchased power costs increased for the three months ended September 30, 2008 compared to the same period in 2007 primarily due to higher natural gas prices. Purchased power costs decreased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to a decrease in volume partially offset by higher natural gas prices. MWhs decreased for the three and nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in the reliance on internal generation and a decrease in total system demand. The average cost per MWh of purchased power increased for the three and nine months ended September 30, 2008 compared to the same period in 2007 primarily due to higher natural gas prices partially offset by a decrease in fixed capacity charges and cost of hedging instruments.

Fuel For Power Generation

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Fuel for power generation	$	240,027	$	166,284		44.3	%	$	613,968	$	471,142		30.3	%

Thousands of MWhs generated		4,317		4,193		3.0	%		11,437		11,127		2.8	%
Average fuel cost per MWh of
generated power	$	55.60	$	39.66		40.2	%	$	53.67	$	42.34		26.8	%

Fuel for power generation costs and the average cost per MWh increased for the three and nine months ended September 30, 2008 primarily due to higher natural gas prices partially offset by a decrease in the cost of hedging instruments. Volume increased for the three and nine months ended September 30, 2008 due to greater reliance on internal generation.

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Deferral of Energy Costs - Net

	Three Months								Nine Months
	Ended September 30,								Ended September 30,
	2008			2007		Change from Prior Year %			2008			2007		Change from Prior Year %

Deferred energy costs - net	$	(80,191	)	$	54,868		-246.2	%	$	(44,107	)	$	149,531		-129.5	%

Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recovered through current rates. To the extent actual costs exceed amounts recovered through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recovered through current rates, the difference is recognized as an increase in costs. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred. Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended September 30, 2008 and 2007 include amortization of deferred energy costs of $37.7 million and $73.0 million, respectively; and an under-collection of amounts recoverable in rates of $115.9 million in 2008 and $18.2 million in 2007. Amounts for the nine months ended September 30, 2008 and 2007 include amortization of deferred energy costs of $123.9 million and $137.8 million, respectively; and an under-collection of amounts recoverable in rates of $168 million in 2008 and an over-collection of $11.8 million in 2007. Amortization for both the three and six month periods include amounts for the western energy crisis rate case and the reinstatement of deferred energy as discussed in Note 3, Regulatory Actions, of Notes to Financial Statements in NPC’s 2007 Form 10-K.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change from Prior Year %			2008		2007		Change from Prior Year %

Allowance for other funds
used during construction	$	6,543	$	4,701		39.2	%	$	21,093	$	11,046		91.0	%

Allowance for borrowed funds used during construction	$	5,128	$	3,936		30.3	%	$	16,503	$	9,189		79.6	%
	$	11,671	$	8,637		35.1	%	$	37,596	$	20,235		85.8	%

AFUDC increased for the three and nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in Construction Work-In-Progress (CWIP) associated with the construction of the Clark Peaking Units. One block was placed in service in July 2008 and the remaining two blocks are scheduled for completion in the fourth quarter of 2008.

Other (Income) and Expenses

	Three Months Ended September 30,									Nine Months Ended September 30,
	2008			2007			Change from Prior Year %			2008			2007			Change from Prior Year %

Other operating expense	$	69,432		$	61,400			13.1	%	$	189,144		$	167,401			13.0	%
Maintenance expense	$	12,469		$	16,360			-23.8	%	$	42,727		$	54,143			-21.1	%
Depreciation and amortization	$	37,902		$	38,151			-0.7	%	$	120,855		$	112,745			7.2	%
Interest charges on long-term debt	$	46,662		$	41,955			11.2	%	$	129,283		$	123,029			5.1	%
Interest charges-other	$	6,737		$	5,876			14.7	%	$	17,952		$	18,315			-2.0	%
Interest accrued on deferred energy	$	(2,803	)	$	(4,573	)		-38.7	%	$	(5,681	)	$	(11,849	)		-52.1	%
Carrying charge for Lenzie		-			-			N/A			-		$	(16,080	)		N/A
Reinstated interest on deferred energy		-			-			N/A			-		$	(11,076	)		N/A
Other income	$	(4,116	)	$	(2,315	)		77.8	%	$	(12,970	)	$	(10,345	)		25.4	%
Other expense	$	2,028		$	1,346			50.7	%	$	5,045		$	8,772			-42.5	%

Other operating expense increased for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to an increase in reserves for uncollectible accounts of approximately $4.5 million, change in account classifications of chemical costs from maintenance expense in 2007 to operating expense in 2008, costs associated with the recently approved Union contract, partially offset by billing adjustments during the period to NPC’s operating partner for Reid Gardner IV.

Other operating expense increased for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to the reversal of a reserve established for Enron legal fees in 2007. In March 2007, the PUCN granted recovery of these expenses, see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2007 Form 10-K for further discussion. Additionally, in 2007 certain consulting fees were reclassified to regulatory asset reducing expense in 2007. Also contributing to the increase in other operating expenses were increased costs for regulatory amortizations in 2008 as compared to the same period in 2007, as well as an increase in reserves for uncollectible accounts and other factors as mentioned above.

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Maintenance expense decreased for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to billing adjustments during the period to NPC’s operating partner for Reid Gardner IV, partially offset by a change in account classification of chemical costs from maintenance expense in 2007 to operating expense in 2008.

Maintenance expense decreased for the nine months ended September 30, 2008, compared to the same period in 2007 due to planned maintenance costs for Lenzie and a forced outage at Harry Allen in 2007.

Depreciation and amortization expenses decreased during the three months ended September 30, 2008, compared to the same periods in 2007, primarily as a result of a deferred tax adjustment for the Temporary Renewable Energy Development trust (“TRED trust”) partially offset by increases to plant-in-service.

Depreciation and amortization expenses increased during the nine months ended September 30, 2008, compared to the same periods in 2007, primarily as a result of depreciation expense related to Lenzie, beginning June 2007 as a result of NPC’s 2006 GRC. The increase was partially offset by the deferred tax adjustment discussed above.

Interest charges on Long-Term Debt increased for the three and nine months ended September 30, 2008, as compared to the same period in 2007, primarily due to the issuance of $500 million Series S General and Refunding Mortgage Notes in July 2008 and higher interest rates on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2007 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q.

Interest charges-other increased for the three months ended September 30, 2008, as compared to the same period in 2007, due to interest expense associated with refunds for construction advances in 2008. Interest charges-other decreased for the nine months ended September 30, 2008, as compared to the same period in 2007, due to lower interest associated with customer transmission deposits, partially offset by interest expense associated with refunds for construction advances, higher amortization costs related to new debt issues, and interest expense related to new leases in 2008.

Interest accrued on deferred energy costs decreased for the three months ended September 30, 2008, as compared to the same period in 2007, due to lower deferred energy balances. Interest accrued on deferred energy costs decreased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to lower deferred energy balances, partially offset by carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Carrying charges for Lenzie represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2007 Form 10-K for discussion of the accounting for the carrying charge for Lenzie.

Reinstated interest on deferred energy represents the carrying charges which were previously expensed as a result of the PUCN’s decision on NPC’s 2001 Deferred Energy Case. In March 2007, PUCN approved a settlement agreement allowing NPC to recover past carrying charges. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2007 Form 10-K.

Other income increased during the three months ended September 30, 2008, as compared to the same period in 2007 primarily due to carrying charges on energy conservation programs. Other income increased during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to carrying charges on energy conservation programs and the gain from the settlement with Calpine, and the subsequent gain on sale of the stock received, as discussed further in Note 6, Commitments and Contingencies in the Consolidated Notes to Financial Statements. This income was partially offset by lower interest income in 2008.

Other expense increased during the three months ended September 30, 2008, as compared to the same period in 2007, due to higher advertising costs in 2008. Other expense decreased during the nine months ended September 30, 2008, as compared to the same period in 2007, due to costs in 2007 associated with the Energy Savings Project for the Clark County School District, as agreed upon in the Reid Gardner Consent Decree discussed in Note 13, Commitments and Contingencies of the Notes to Financial Statements in the 2007 Form 10-K.

ANALYSIS OF CASH FLOWS

Cash flows increased during the nine months ended September 30, 2008 compared to the same period in 2007 due to a decrease in cash used for investing activities and an increase in cash from financing activities, offset partially by a decrease in cash from operating activities.

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Cash From Operating Activities . The decrease in cash from operating activities was due primarily to increases in energy costs in excess of the energy revenue collected in rates, an increase in expenditures for conservation programs, site studies and other regulatory activities in 2008 and a prepayment of tax obligations. The decrease was partially offset by the settlement with Calpine, a reduction in funding for retirement plans and prepaid transmission revenue.

Cash Used By Investing Activities . Cash used by investing activities decreased primarily due to the closing stages of major construction activity for the peaking units at Clark Station, which began in 2007, and a reduction in construction for infrastructure.

Cash From Financing Activities . Cash from financing activities increased due to the proceeds from the issuance of $500 million of 6.5% General and Refunding Mortgage Notes, Series S, due 2018 and an investment of $133 million by SPR, partially offset by higher dividends paid to SPR.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions.

Available Liquidity as of September 30, 2008 (in millions)

Cash and Cash Equivalents	$	177.7
Balance available on Revolving Credit Facility (1)(2)	$	585.4

	$	763.1

(1) The available balance reflects management's estimate of a reduction of approximately $11 million as a result of the bankruptcy of a lending bank.

(2) As of November 4, 2008, NPC had approximately $232.2 million available under its revolving credit facility.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as United States treasury bills. In addition to cash on hand and the revolving credit facility, NPC may issue debt up to $665 million on a consolidated basis, subject to certain limitations discussed below.

For the nine months ended September 30, 2008, SPR contributed capital to NPC of approximately $133 million for general corporate purposes. For the nine months ended September 30, 2008, NPC paid dividends to SPR of $54.9 million.

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facility. To manage liquidity needs as a result of seasonal peaks in fuel requirements, NPC may use hedging activities. In order to fund long-term capital requirements, NPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facility, the issuance of long-term debt, and capital contributions from SPR. In October 2008, NPC borrowed approximately $466.4 million from its revolving credit facility, along with cash on hand, to fund the approximately $510 million acquisition of the Bighorn Generating Facility from Reliant Resources. As discussed earlier in the executive overview, NPC has reduced its capital expenditures for the remainder of 2008 and for 2009 as a result of current economic conditions.

Detailed below and included in financing transactions are material changes to contractual obligations as set forth in NPC’s 2007 Form 10-K. In April 2008, NPC entered into a Purchase Agreement with Reliant Resources, for the Bighorn Power Plant, a 598 MW (nominally rated), natural gas fired combined cycle facility, for approximately $510 million. As stated above, this agreement was consummated in October. Along with the purchase, NPC assumed a long-term service agreement related to Bighorn. In June 2008, NPC entered into an equipment contract for approximately $43.5 million related to the construction of Harry Allen. Additionally, in October 2008, NPC entered into an equipment, procurement and construction contract for Harry Allen for approximately $416.8 million.

Financing Transactions

General and Refunding Mortgage Notes, Series S

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Redemption Notice

Conversion of Coconino County Pollution Control Refunding Revenue Bonds and Clark County Pollution Control Revenue Bonds

In July 2008, NPC converted the $13 million principal amount Coconino County, Arizona Pollution Control Refunding Revenue Bonds Series 2006B bonds, due 2039 and the $15 million principal amount Clark County Nevada Pollution Control Revenue Bonds, Series 2000B due 2009, (collectively, the “Bonds”) from auction rate securities to variable rate demand notes. The purpose of these conversions was to reduce interest costs and volatility associated with these Bonds. NPC purchased 100% of the Bonds with the use of its revolving credit facility and available cash, and are the sole holder of the Bonds until such time as NPC determines to reoffer the Pollution Control Bonds to investors. The Bonds remain outstanding and have not been retired or cancelled. However, as NPC is the sole holder of the Bonds, for financial reporting purposes the investment in the Bonds and the indebtedness will be offset for presentation purposes.

Factors Affecting Liquidity

Financial Covenants

NPC's $600 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires NPC to 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 NPC to 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, 2008, NPC was in compliance with these covenants.

Ability to Issue Debt

Ability to Issue General and Refunding Mortgage Securities

Credit Ratings

NPC’s debt is rated investment grade by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch, Moody’s and S&P. As of October 31, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB (low)	BBB-	Baa3	BBB
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	BB+

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On May 15, 2008, S&P increased NPC’s secured ratings to BBB from BB+, and the unsecured notes to BB+ from BB. S&P’s, Moody’s and DBRS’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.

Credit Ratings of Bond Insurers

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and downgrades of bond insurers, among other negative matters. The interest rates on certain issues of NPC’s auction rate securities of approximately $179.5 million, as of September 30, 2008, are periodically reset through auction processes. These securities are supported by bond insurance policies provided by either AMBAC or FGIC and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. S&P’s and Moody’s ratings on these bonds are the higher of a bond issue's underlying rating and the Insurer's rating. As of September 30, 2008, AMBAC’s credit rating was investment grade. However, FGIC’s credit ratings were below investment grade. As a result, the bonds insured by FGIC are currently rated at the investment grade rating of NPC’s secured debt. See Credit Ratings above .

The uncertainty with the Insurers' credit quality has had an impact on NPC’s interest costs for the nine months ended September 30, 2008. With the ongoing review of the credit ratings of the Insurers, NPC is experiencing higher interest costs for these securities, with interest rates on these bonds during the third quarter 2008, ranging from a low of 4.92% to a high of 10.20% , and a low of 4.10% to a high of 10.20% for the nine months ended September 30, 2008, with a weighted average interest rate of 5.88% for the nine months ended September 30, 2008.

In July 2008, NPC converted the Coconino County Arizona Pollution Control Revenue Bonds, Series 2006B, and the Clark County Pollution Control Revenue Bonds, Series 2000B from auction rate securities to variable rate demand notes. This conversion will likely result in higher interest charges compared to prior year, but lower than the failed auction rates for this tax exempt debt. See Financing Transactions above. If higher interest rates continue on the remaining auction rate securities outstanding, NPC may seek to convert the debt to other short-term variable rate structures, term-put structures and/or fixed-rate structures.

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by SPR or SPPC under any of its financing agreements. In addition, 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 such other indebtedness when due) 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.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $32.9 million for the three months ended September 30, 2008 compared to net income of $25.6 million for the same period in 2007. During the nine months ended September 30, 2008, SPPC recognized net income of approximately $68.1 million compared to $57.5 million for the same period in 2007.

During the nine months ended September 30, 2008, SPPC paid $78.3 million in dividends to SPR. On October 30, 2008, SPPC declared a dividend to SPR of $160 million.

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, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, 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.

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 2, Segment Information in the Condensed Notes to Financial Statements. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended September 30,								Nine Months Ended September 30,
						Change from								Change from
	2008			2007		Prior Year %			2008			2007		Prior Year %
Operating Revenues:
Electric	$	271,919		$	290,979		-6.6	%	$	758,612		$	789,214		-3.9	%
Gas		19,379			20,839		-7.0	%		137,125			137,337		-0.2	%
	$	291,298		$	311,818		-6.6	%	$	895,737		$	926,551		-3.3	%

Energy Costs:
Purchased power	$	64,005		$	96,980		-34.0	%	$	251,474		$	266,599		-5.7	%
Fuel for power generation		92,845			71,896		29.1	%		211,137			187,250		12.8	%
Deferral of energy costs-electric-net		(9,384	)		11,792		-179.6	%		(12,572	)		44,423		-128.3	%
Gas purchased for resale		13,760			11,661		18.0	%		108,288			103,169		5.0	%
Deferral of energy costs-gas-net		(725	)		2,594		-127.9	%		(2,296	)		4,203		-154.6	%
	$	160,501		$	194,923		-17.7	%	$	556,031		$	605,644		-8.2	%

Energy Costs by Segment:
Electric	$	147,466		$	180,668		-18.4	%	$	450,039		$	498,272		-9.7	%
Gas		13,035			14,255		-8.6	%		105,992			107,372		-1.3	%
	$	160,501		$	194,923		-17.7	%	$	556,031		$	605,644		-8.2	%

Gross Margin by Segment:
Electric	$	124,453		$	110,311		12.8	%	$	308,573		$	290,942		6.1	%
Gas		6,344			6,584		-3.6	%		31,133			29,965		3.9	%
	$	130,797		$	116,895		11.9	%	$	339,706		$	320,907		5.9	%

Electric gross margin increased for the three and nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in BTGR as a result of SPPC’s 2007 GRC, effective July 1, 2008 and an increase in customer growth. Partially offsetting the increase was a decrease in customer usage primarily due to milder weather.

Gas gross margin decreased for the three months ended September 30, 2008 compared to the same period in 2007 primarily due to a decrease in customer growth, partially offset by an increase in customer usage. Gas gross margin increased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in customer usage as a result of colder temperatures, partially offset by a decrease in customer growth.

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

Electric Operating Revenue

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from Prior Year %							Change from Prior Year %
	2008		2007		Change from Prior Year %			2008		2007		Change from Prior Year %
Electric operating revenues:
Residential	$	96,558	$	93,353		3.4	%	$	256,726	$	251,709		2.0	%
Commercial		108,596		111,701		-2.8	%		289,327		294,574		-1.8	%
Industrial		59,163		77,816		-24.0	%		187,942		219,690		-14.5	%
Retail revenues		264,317		282,870		-6.6	%		733,995		765,973		-4.2	%
Other		7,602		8,109		6.3	%		24,617		23,241		5.9	%
Total revenues	$	271,919	$	290,979		-6.6	%	$	758,612	$	789,214		-3.9	%

Retail sales in thousands
of megawatt-hours (MWh)		2,339		2,394		-2.3	%		6,537		6,632		-1.4	%

Average retail revenue per MWh	$	113.00	$	118.16		-4.4	%	$	112.28	$	115.50		-2.8	%

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Retail revenues decreased for the three and nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to lower industrial revenue, decreases in retail rates, and decreased customer usage due to cooler summer temperatures. Industrial revenues decreased primarily due to a new retail service agreement with Newmont Mining Corporation (Newmont) beginning in June 2008 and the transition of two large industrial customers to distribution only service and standby service during the second quarter of 2007. Retail rates decreased as a result of SPPC’s various Base Tariff Energy Rate (BTER) quarterly cases and the annual Deferred Energy case but were partially offset by increased Base Tariff General Rates (BTGR) as a result of the general rate case effective July 1, 2008 (see Note 3, Regulatory Actions of the Condensed Notes to Financial Statements). The average number of residential, commercial, and industrial customers increased by 0.3%, 1.2%, and 9.7% respectively, for the three months ended September 30, 2008. The average number of residential, commercial and industrial customers increased by 0.7%, 2.0%, and 4.5% respectively for the nine months ended September 30, 2008.

In 2007, SPPC and Newmont entered into a wholesale power sale agreement and a new form of retail service, whereby Newmont will sell the electrical output from it’s generating plant to SPPC for at least 15 years under a long-term wholesale purchase power agreement and remain a retail customer of SPPC during at least that period under the terms of the retail service agreement and pursuant to a new rate schedule. The terms of these contracts became effective on June 1, 2008, at which point Newmont moved to a new retail service agreement at a reduced energy rate, which resulted in decreased electric revenues.

Electric Operating Revenues – Other decreased for the three months ended September 30, 2008 compared to the same period in 2007 primarily due to a decrease in charges related to the departure of Barrick Gold from SPPC’s system.

Electric Operating Revenues – Other increased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to increased transmission wheeling revenues partially offset by decreases in charges related to the departure of Barrick Gold from SPPC’s system.

Gas Operating Revenues

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %
Gas operating revenues:
Residential	$	10,269	$	11,384		-9.8	%	$	79,074	$	76,592		3.2	%
Commercial		4,885		5,415		-9.8	%		37,768		37,255		1.4	%
Industrial		1,873		2,600		-28.0	%		13,726		13,605		0.9	%
Retail revenues		17,027		19,399		-12.2	%		130,568		127,452		2.4	%
Wholesale revenue		1,858		943		97.0	%		4,663		7,922		-41.1	%
Miscellaneous		494		497		-0.6	%		1,894		1,963		-3.5	%
Total revenues	$	19,379	$	20,839		-7.0	%	$	137,125	$	137,337		-0.2	%

Retail sales in thousands
of decatherms		1,231		1,318		-6.6	%		10,420		9,797		6.4	%

Average retail revenue per decatherm	$	13.83	$	14.72		-6.0	%	$	12.53	$	13.01		-3.7	%

Retail gas revenues decreased for the three months ended September 30, 2008 as compared to the same period in the prior year primarily due to decreased retail rates and decreases in customer usage due to warmer 2008 fall temperatures. Retail rates decreased as a result of SPPC’s 2007 and 2008 Natural Gas and Propane Deferred Rate Case and BTER updates. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K and Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. Average retail customers increased by 1.4%.

Retail gas revenues increased for the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to colder winter temperatures and retail customer growth in 2008. The average number of retail customers increased by 1.0% for the nine months ended September 2008. These increases were partially offset by decreased retail rates as a result of SPPC’s 2007 and 2008 Natural Gas and Propane Deferred Rate Case and BTER updates.

Wholesale revenue increased for the three month period ended September 30, 2008, compared to the same period in 2007 primarily due to increased availability of gas for wholesale sales. However, wholesale revenues for the nine months ended September 30, 2008, decreased compared to prior year primarily due to decreased availability of gas for wholesale sales during the first quarter of 2008.

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Energy Costs

Energy Costs include Purchased Power and Fuel for Generation. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Purchased Power versus Fuel for Generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:

Weather

·	Plant outages

·	Total system demand

·	Resource constraints

·	Transmission constraints

·	Gas transportation constraints

·	Natural gas constraints

·	Long term contracts

·	Mandated power purchases; and

·	Generation efficiency

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Energy Costs	$	156,850	$	168,876		-7.1	%	$	462,611	$	453,849		1.9	%
Total System Demand		2,455		2,582		-4.9	%		6,986		7,123		-1.9	%
Average cost per MWh	$	63.89	$	65.40		-2.3	%	$	66.22	$	63.72		3.9	%

Energy costs and the average cost per MWh for the three months ended September 30, 2008 decreased compared to the same period in 2007 primarily due to the long term purchase power contract with Newmont effective June 1, 2008, as discussed above in electric operating revenues, and an increased reliance on internal generation.

Energy costs and the average cost per MWh for the nine months ended September 30, 2008 increased compared to the same period in 2007 due to higher natural gas prices.

Purchased Power

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Purchased power	$	64,005	$	96,980		-34.0	%	$	251,474	$	266,599		-5.7	%

Purchased power in thousands of MWhs		977		1,347		-27.5	%		3,661		4,127		-11.3	%

Average cost per MW purchased power	$	65.51	$	72.00		-9.0	%	$	68.69	$	64.60		6.3	%

Purchased Power costs and volume decreased for the three and nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to the long-term purchase power contract with Newmont effective June 1, 2008, as discussed above in electric operating revenues, and an increased reliance on internal generation.

The average cost per MWh decreased for the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to the Newmont contract. The average cost per MWh increased for the nine months ended September 30, 2008 compared to the prior year primarily due to higher natural gas prices.

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Fuel for Power Generation

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Fuel for power generation	$	92,845	$	71,896		29.1	%	$	211,137	$	187,250		12.8	%

Thousands of MWh generated		1,478		1,235		19.7	%		3,325		2,996		11.0	%

Average fuel cost per MWh
of generated power	$	62.82	$	58.22		7.9	%	$	63.50	$	62.50		1.6	%

Fuel for power generation and average cost per MWh increased for the three months and nine months ended September 30, 2008, as compared to the same period in 2007, due to higher natural gas prices, which were partially offset by a decrease in the cost of hedging instruments. Also partially offsetting increased fuel for generation costs and the average cost per MWh was the increased reliance on Valmy in 2008, which is a coal generating facility. The availability of Valmy in 2007 was limited due to outages. The cost of natural gas is significantly higher than the cost of coal.

The volume of MWhs increased for the three and nine months due to increased reliance on internal generation, as it was more economical to generate than purchase power. Additionally, the Tracy expansion became commercially operable early in the third quarter, increasing SPPC’s availability of internal generation.

Gas Purchased for Resale

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %


Gas purchased for resale	$	13,760	$	11,661		18.0	%	$	108,288	$	103,169		5.0	%

Gas purchased for resale
(in thousands of decatherms)		1,510		1,553		-2.8	%		11,221		11,348		-1.1	%

Average cost per decatherm	$	9.11	$	7.51		21.3	%	$	9.65	$	9.09		6.2	%

Gas purchased for resale and average cost per decatherm increased for the three and nine months ended September 30, 2008 as compared to the same period in 2007. The increase is primarily due to an increase in natural gas prices which were partially offset by lower costs associated with the settlement of hedging instruments. Volume decreased for the three and nine months ended September 30, 2008 compared to the same period in 2007 primarily due to milder weather in the third quarter 2008.

Deferral of Energy Costs – Electric - Net

	Three Months Ended September 30,								Nine Months Ended September 30,
	2008			2007		Change from Prior Year %			2008			2007		Change from Prior Year %

Deferred energy costs - electric – net	$	( 9,384	)	$	11,792		-179.6	%	$	(12,572	)	$	44,423		-128.3	%
Deferred energy costs - gas – net	$	(725	)		2,594		-128.0	%	$	(2,296	)		4,203		-154.6	%
	$	(10,108	)	$	14,386				$	(14,868	)	$	48,626

Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recovered through current rates. To the extent actual costs exceed amounts recovered through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recovered through current rates the difference is recognized as an increase in costs. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Deferral of energy costs - electric – net for the three months ended September 30, 2008 and 2007 reflect amortization of deferred energy costs of ($2 million) and $10.7 million respectively; and an under-collection of amounts recoverable in rates of $7.4 million in 2008, and an over-collection of $1.1 million in 2007. For the nine months ended September 30, 2008 and 2007, amortization of deferred energy costs were $16.6 million and $34.5 million, respectively; with an under-collection of amounts recoverable in rates of $29.2 million in 2008, and over-collection of $10 million in 2007.

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Deferred energy costs - gas - net for the three months ended September 30, 2008 and 2007 reflect amortization of deferred energy costs of ($0.1) million, and $0.1 million, respectively; and an under-collection of amounts recoverable in rates in 2008 of $0.6 million and an over-collection of $2.5 million in 2007. For the nine months ended September 30, 2008 and 2007, amortization of deferred energy costs were ($1) million and $0.7 million, respectively; with an under-collection of amounts recoverable in rates of $1.3 million and an over-collection of $3.5 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change from Prior Year %			2008		2007		Change from Prior Year %

Allowance for other funds
used during construction	$	1,322	$	4,513		-70.7	%	$	11,842	$	11,347		4.4	%

Allowance for borrowed funds used during construction	$	1,050	$	3,625		-71.0	%	$	8,915	$	9,080		-1.8	%
	$	2,372	$	8,138		-70.8	%	$	20,758	$	20,427		1.6	%

AFUDC decreased for the three months ended September 30, 2008 compared to the same period in 2007 due to the completion of the Tracy Expansion in July 2008.

AFUDC increased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in Construction Work-In-Progress (CWIP) associated with the expansion of the Tracy Generating Station.

Other (Income) and Expense

	Three Months Ended September 30,									Nine Months Ended September 30,
	2008			2007			Change from Prior Year %			2008			2007			Change from Prior Year %

Other operating expense	$	35,474		$	36,228			-2.1	%	$	103,744		$	105,070			-1.3	%
Maintenance expense	$	7,868		$	6,948			13.2	%	$	22,204		$	23,543			-5.7	%
Depreciation and amortization	$	21,343		$	20,726			3.0	%	$	64,801		$	62,043			4.4	%
Interest charges on long-term debt	$	18,635		$	17,096			9.0	%	$	55,975		$	49,746			12.5	%
Interest charges-other	$	1,407		$	1,491			-5.6	%	$	4,398		$	4,533			-3.0	%
Interest accrued on deferred energy	$	454		$	(60	)		-856.7	%	$	1,639		$	(1,171	)		-240.0	%
Other income	$	(2,367	)	$	(1,865	)		26.9	%	$	(11,331	)	$	(6,707	)		68.9	%
Other expense	$	749		$	2, 938			-74.5	%	$	5,430		$	7,143			-24.0	%

Other operating expense decreased for the three and nine months ended September 30, 2008 compared to the same period in 2007 due to several items, none of which was individually significant.

Maintenance expense increased for the three months ended September 30, 2008 compared to the same period in 2007 mainly due to increased compliance costs associated with the North American Electric Reliability Corporation (NERC), the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.

Maintenance expense decreased for the nine months ended September 30, 2008 compared to the same period in 2007 mainly due to outages in 2007 at Valmy Unit 2 for turbine and boiler tube repairs; partially offset by increased compliance costs associated with NERC.

Depreciation and amortization expenses increased for the three and nine months ended September 30, 2008 compared to the same period in 2007 primarily as a result of increases to plant-in-service. The increase is primarily due to completion of Tracy Expansion in July 2008. This increase was partially offset by a deferred tax adjustment for the Temporary Renewable Energy Development trust (“TRED trust”).

Interest charges on long-term debt increased for the three months ended September 30, 2008 compared to the same period in 2007 primarily due to the issuance of $250 million Series Q General and Refunding Mortgage Notes in September 2008 and higher interest rates for variable rate debt in 2008 and interest for the revolving credit facility partially offset by the redemption of $99 million Series A General and Refundi ng Mortgage Bonds in June 2008.

Interest charges on long-term debt increased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to the reasons noted above and the issuance of the $325 million Series P General and Refunding Mortgage Notes in June 2007, partially offset by the redemption of the $ 221 million Series A General and Refunding Mortgage Bonds in June 2007. See Note 4, Long-Term Debt, of the Notes to Financial Statements in the 2007 Form 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q.

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Interest charges-other for the three months and nine months ended September 30, 2008 was comparable to the same period in 2007.

Interest accrued on deferred energy costs decreased for the three months and nine months ended September 30, 2008 due to over collected deferred energy in 2008. See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income increased slightly for the three months ended September 30, 2008 compared to the same period in 2007 for individual items, none of which was significant.

Other income increased during the nine months ended September 30, 2008, when compared to the same period in 2007, primarily due to the reinstatement of previously disallowed costs associated with Pinon Pine, as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements, and the settlement with Calpine, as discussed further in Note 6, Commitments and Contingencies of the Condensed Notes to Financial Statements. This increase was partially offset by lower interest income on investments and a refund of expenses in 2007.

Other expense decreased during the three months and nine months ended September 30, 2008, when compared to the same period in 2007, due primarily to development costs in 2007 associated with an information technology system conversion project.

ANALYSIS OF CASH FLOWS

Cash flows increased during the nine months ended September 30, 2008 compared to the same period in 2007 due to the decrease in cash used for investing activities, partially offset by a decrease in cash from operating and financing activities.

Cash Used By Investing Activities . Cash used by investing activities decreased primarily due to the closing stages of major construction activity at the Tracy Generating Station, which began in 2006.

Cash From Financing Activities . The decrease in cash from financing activities is due to a reduction in debt financing in 2008 and higher dividend payments to SPR, partially offset by a $20 million investment by SPR.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of September 30, 2008 (in millions)
Cash and Cash Equivalents	$	29.3
Balance available on Revolving Credit Facility (1)(2)	$	313.2

	$	342.5

(1) The available balance reflects management's estimate of a reduction of approximately $18 million as a result of the bankruptcy of a lending bank.

(2) As of November 4, 2008, SPPC had approximately $266.1 million available under its revolving credit facility.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as United States treasury bills. In addition to cash on hand and the revolving credit facility, SPPC may issue debt up to $665 million on a consolidated basis, subject to certain limitations discussed below.

For the nine months ended September 30, 2008, SPR contributed capital to SPPC of approximately $20 million for general corporate purposes. For the nine months ended September 30, 2008, SPPC paid dividends to SPR of approximately $78.3 million. On October 30, 2008 SPPC declared an additional dividend to SPR for $160 million.

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of its revolving credit facility. To manage liquidity needs as a result of seasonal peaks in fuel requirements, SPPC may use hedging activities. In order to fund long-term capital requirements, SPPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facility, issuance of long-term debt, and capital contributions from SPR. However, as discussed earlier in the executive overview, SPPC has reduced its capital expenditures for the remainder of 2008 and for 2009 as a result of current economic conditions.

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During the nine months ended September 30, 2008, there were no material changes to contractual obligations as set forth in SPPC’s 2007 Form 10-K, except as discussed under financing transactions below.

Financing Transactions

Conversion of Humboldt County Pollution Control Refunding Revenue Bonds Series 2006

In October 2008, SPPC converted the $49.8 million principal amount, Humboldt County, Nevada Pollution Control Refunding Revenue Bonds Series 2006 bonds, due 2029 (the “Pollution Control Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Pollution Control Bonds on that date, with the use of its revolving credit facility and available cash, and are the sole holder of the Pollution Control Bonds until such time as SPPC determines to reoffer the Pollution Control Bonds to investors. The Pollution Control Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Pollution Control Bonds, for financial reporting purposes the investment in the Pollution Control Bonds and the indebtedness will be offset for presentation purposes.

General and Refunding Mortgage Notes, Series Q

On September 2, 2008, SPPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 . The net proceeds of the issuance were used to repay $238 million of amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Maturity of General and Refunding Mortgage Bonds, Series A

On June 2, 2008, the 8.00% General and Refunding Mortgage Bonds, Series A, in the aggregate principal amount of approximately $99.2 million, matured. SPPC paid for the maturing debt plus interest with $90 million from its revolving credit facility, which was repaid with the proceeds of the Series Q offering, plus cash on hand.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In July 2008, SPPC converted the $40 million principal amount Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007B bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and are the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.

Factors Affecting Liquidity

Financial Covenants

SPPC's $350 million Second Amended and Restated Revolving Credit Agreement dated November 2005, as amended in April 2006, contains two financial maintenance covenants. The first requires SPPC to 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 SPPC to 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, 2008, SPPC was in compliance with these covenants.

Ability to Issue Debt

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Ability to Issue General and Refunding Mortgage Securities

Credit Ratings

SPPC’s debt is rated investment grade by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch, Moody’s and S&P. As of October 31, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB (low)	BBB-	Baa3	BBB

On May 15, 2008, S&P increased SPPC’s secured ratings to BBB from BB+. S&P’s, Moody’s and DBRS’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.

Credit Ratings of Bond Insurers

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and downgrades of bond insurers, among other negative matters. The interest rates on certain issues of SPPC’s auction rate securities of approximately $ 308.3 million as of September 30, 2008 are periodically reset through auction processes. These securities are supported by bond insurance policies provided by the Insurers and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. S&P’s and Moody’s ratings on these bonds are the higher of a bond issue’s underlying rating and the Insurer's rating. As of September 30, 2008, Ambac’s and MBIA’s credit ratings were investment grade or above. However, FGIC’s credit ratings were below investment grade. As a result, the bonds insured by FGIC are currently rated at the investment grade rating of SPPC’s secured debt. See Credit Ratings above.

The uncertainty with the Insurers' credit quality has had an impact on SPPC’s interest costs for the first nine months of 2008. With the ongoing review of the credit ratings of the Insurers, SPPC is experiencing higher interest costs for these securities, with interest rates on these bonds during the third quarter 2008, ranging from a low of 4.32% to a high of 10.20%, and a low of 3.64% to a high of 10.20% for the nine months ended September 30, 2008, with a weighted average interest rate of 5.57% for the nine months ended September 30, 2008.

In July and October 2008, SPPC converted the $40 million of Water Bonds and $49.8 million Pollution Control Bonds from auction rate securities to variable rate demand notes. This conversion will likely result in higher interest charges compared to prior year, but lower than the failed auction rates for this tax exempt debt. See Financing Transactions above. If higher interest rates continue on the remaining auction rate securities outstanding, SPPC may seek to convert the debt to other short-term variable rate structures, term-put structures and/or fixed-rate structures.

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 such other indebtedness when due) 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.

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REGULATORY PROCEEDINGS (UTILITIES)

SPR is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, SPR and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and the California Public Utilities Commission (CPUC). In addition, the PUCN, CPUC, or the FERC have the authority to review allocations of costs of non-power goods and administrative services among SPR and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between SPR, NPC and/or SPPC and/or any other affiliated company.

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 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 Utilities are required to file annual electric and gas Deferred Energy Accounting Adjustment (DEAA) cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly Base Tariff Energy Rate (BTER) updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER updates recover current energy costs. As of September 30, 2008, NPC’s and SPPC’s balance sheets included approximately $334.7 million and credit of $14.9 million, respectively, of deferred energy costs of which $159.7 million and a credit of $44.5 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

Rate case applications filed in 2007 and 2008, as well as other regulatory matters such as the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.

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ITEM 3 . QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2008, SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

		Expected Maturity Date
									Fair
		2008	2009	2010	2011	2012	Thereafter	Total	Value
Long-term Debt
	SPR
	Fixed Rate	$ -	$ -	$ -	$ -	$ 63,670	$ 460,539	$ 524,209	$ 505,281
	Average Interest Rate	-	-	-	-	7.80%	7.77%	7.77%

	NPC
	Fixed Rate	$ -	$ -	$ -	$ 364,000	$ 130,000	$2,269,335	$2,763,335	$2,569,160
	Average Interest Rate	-	-	-	8.14%	6.50%	6.35%	6.60%
	Variable Rate	$ -	$ -	$ -	$ -	$ -	$ 179,500	$ 179,500	$ 179,500
	Average Interest Rate	-	-	-	-	-	5.88%	5.88%

	SPPC
	Fixed Rate	$ 539	$ 600	$ -	$ -	$ 100,000	$ 875,000	$ 976,139	$ 919,696
	Average Interest Rate	6.40%	6.40%	-	-	6.25%	6.12%	6.13%
	Variable Rate	$ -	$ -	$ -	$ -	$ -	$ 308,250	$ 308,250	$ 308,250
	Average Interest Rate	-	-	-	-	-	5.57%	5.57%

	Total Debt	$ 539	$ 600	$ -	$ 364,000	$ 293,670	$4,092,624	$ 4,751,433	$4,481,887

Commodity Price Risk

See the 2007 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2007.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $266.3 million as of September 30, 2008, which decreased from the $865.4 million balance at June 30, 2008 and increased from the $4.9 million balance at December 31, 2007. Approximately $390.6 million of the decrease from June 30, 2008 is primarily the result of decreased prices of oil and natural gas during the third quarter of 2008. The remainder of the decrease from June 30, 2008, or $208.5 million, is related to a reduction in credit risk exposure total related to the 10-year tolling agreement with Dynegy Power Marketing (“DPM”) for the entire output of the 570 MW Griffith Energy Facility that was executed during the second quarter of 2008. The increase from the December 31, 2007 balance is primarily due to the aforementioned DPM tolling agreement which has a $244.7 credit risk total at September 30, 2008.

ITEM 4 AND ITEM 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

SPR, NPC, and SPPC management, under the supervision and with the participation of the company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of SPR, NPC, and SPPC disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, SPR, NPC, and SPPC disclosure and procedures are effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the third quarter of 2008 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

As of the date of this report, there have been no material changes with regard to administrative and judicial proceedings involving regulatory, environmental and other matters as disclosed in SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2007, and quarterly reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to SPR on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2007 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in SPR’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2007, and quarterly reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

Election of New Director

On October 30, 2008, Susan F. Clark, an attorney with 28 years experience specializing in energy law and utility regulation matters, was elected to SPR's board of directors, effective immediately. Previously, Ms. Clark formerly served as chairman of the state of Florida's Public Service Commission. Ms. Clark will serve on the Compensation and Planning & Finance Committees. Ms. Clark will receive the same compensation and participate in the same plans as are provided to all of SPR's non-employee directors, as more fully described in SPR's definitive Proxy Statement filed on March 19, 2008.

Amendments to By-laws of Sierra Pacific Resources

On October 31, 2008, the Board approved amendments to the By-Laws of SPR (the “ By-Laws ”), as follows:

(1) Amended Article XXV of the By-laws (Certificated and Uncertificated Shares) to provide that the Board is authorized to issue any of the classes or series of shares of the corporation’s capital stock with or without certificates, to set forth the requirements with respect to any certificates that are issued, and to specify that the corporation will provide to holders of uncertificated shares all of the information required to be provided pursuant to applicable law.

(2) Amended Articles XXVI and XXVIII of the By-laws (Transfer of Stock and Loss of Certificates) to add procedures to be followed with respect to uncertificated shares.

(3) Deleted Article XXXII, Section 5 (Special Provisions) of the By-laws.

(4) Amended Article XXXIII of the By-laws (Advance Notification of Proposals at Stockholder’s Meetings) to provide that any stockholder who desires to submit a proposal for consideration at an annual or special stockholders’ meeting or to nominate persons for election as directors at any stockholders’ meeting must set forth in a written notice to the Secretary of the corporation, in addition to information already required by Article XXXIII, whether and the extent to which any hedging or other transaction has been entered into by or on behalf of the stockholder or any associated person, or whether any other agreement, arrangement or understanding (including any short position or any borrowing or lending of shares) has been made, the effect or intent of which is to increase or decrease the voting power of such stockholder or associated person with respect to any share of stock of the corporation.

The foregoing summary of the amendments to the By-Laws is qualified in its entirety by reference to the By-Laws, as amended, which are filed as Exhibit 3.1 hereto and incorporated herein by reference. The effective date of such amendments is October 31, 2008.

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ITEM 6. EXHIBITS

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

(3) Sierra Pacific Resources

3.1 By-laws of Sierra Pacific Resources as amended through October 31, 2008.

(12) Sierra Pacific Resources:

12.1 Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company:

12.2 Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company:

12.3 Statement regarding computation of Ratios of Earnings to Fixed Charges .

(31) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

31.1 Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 .

31.2 Annual Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3 Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4 Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.5 Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

32.1 Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3 Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4 Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.5 Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Table of Contents

SIGNATURES

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


	Sierra Pacific Resources
	(Registrant)

Date: November 4, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: November 4, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)



	Nevada Power Company d/b/a NV Energy
	(Registrant)

Date: November 4, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: November 4, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)



	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)

Date: November 4, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: November 4, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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