Sierra Pacific Resources /NV/ - 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 June 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	88-0420104	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 367-5000

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

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 August 1, 2008
Common Stock, $1.00 par value of Sierra Pacific Resources		234,088,844 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 JUNE 30, 2008

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements

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

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

Sierra Pacific Power Company —
Consolidated Balance Sheets — June 30, 2008 and December 31, 2007			9
Consolidated Income Statements — Three Months and Six Months Ended June 30, 2008 and 200 7			10
Consolidated Statements of Cash Flows — Six Months Ended June 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			29
Sierra Pacific Resources			33
Nevada Power Company			38
Sierra Pacific Power Company			45

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk			54

ITEM 4 and 4T. Controls and Procedures			54

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings			55
ITEM 1A. Risk Factors			57
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			57
ITEM 3. Defaults Upon Senior Securities			57
ITEM 4. Submission of Matters to a Vote of Security Holders			57
ITEM 5. Other Information			58
ITEM 6. Exhibits			59

Signature Page and Certifications			60

Table of Contents

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
		June 30,		December 31,
		2008		2007
		(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service		$	8,640,135	$	8,468,711
Less accumulated provision for depreciation			2,563,250		2,526,379
			6,076,885		5,942,332
Construction work-in-progress			1,248,726		1,068,666
			7,325,611		7,010,998

Investments and other property, net			30,952		31,061

Current Assets:
Cash and cash equivalents			70,825		129,140
Accounts receivable less allowance for uncollectible accounts:
	2008 - $28,556; 2007-$36,061		464,207		434,359
Deferred energy costs - electric (Note 1)			67,944		75,948
Materials, supplies and fuel, at average cost			120,199		117,483
Risk management assets (Note 5)			327,784		22,286
Deferred income taxes			67,177		43,295
Other			36,980		45,909
			1,155,116		868,420
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			179,718		205,030
Regulatory tax asset			264,250		267,848
Regulatory asset for pension plans			189,279		133,984
Other regulatory assets			784,029		758,287
Risk management assets (Note 5)			58,022		12,429
Risk management regulatory assets - net (Note 5)			-		26,067
Unamortized debt issuance costs			61,075		65,218
Other			129,119		85,408
			1,665,492		1,554,271
TOTAL ASSETS		$	10,177,171	$	9,464,750
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,024,027	$	2,996,575
Long-term debt			4,451,781		4,137,864
			7,475,808		7,134,439
Current Liabilities:
Current maturities of long-term debt			10,298		110,285
Accounts payable			388,460		357,867
Accrued interest			68,703		69,485
Accrued salaries and benefits			27,140		35,020
Current income taxes payable			1,344		3,544
Risk management liabilities (Note 5)			4,108		39,509
Accrued taxes			9,013		8,336
Deferred energy costs-electric (Note 1)			17,614		17,573
Deferred energy costs - gas (Note 1)			11,400		11,369
Other current liabilities			85,317		65,991
			623,397		718,979
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			889,305		852,630
Deferred investment tax credit			27,408		28,895
Regulatory tax liability			26,901		28,445
Customer advances for construction			97,829		100,125
Accrued retirement benefits			148,353		77,525
Risk management liabilities			4,684		7,369
Risk management regulatory liability - net (Note 5)			353,272		-
Regulatory liabilities			318,958		304,026
Other			211,256		212,317
			2,077,966		1,611,332
TOTAL CAPITALIZATION AND LIABILITIES		$	10,177,171	$	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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007

OPERATING REVENUES:
Electric	$	806,638		$	820,464		$	1,526,088		$	1,491,508
Gas		32,152			31,378			117,746			116,498
Other		4			52			11			319
		838,794			851,894			1,643,845			1,608,325
OPERATING EXPENSES:
Operation:
Purchased power		261,450			262,025			445,306			440,929
Fuel for power generation		270,625			192,058			492,233			420,212
Gas purchased for resale		27,632			19,862			94,528			91,508
Deferral of energy costs - electric - net		(21,386	)		86,501			32,896			127,294
Deferral of energy costs - gas - net		(3,774	)		3,554			(1,571	)		1,609
Other		98,647			92,268			190,322			177,015
Maintenance		21,472			30,633			44,594			54,378
Depreciation and amortization		64,341			59,678			126,411			115,911
Taxes:
Income taxes		12,928			7,244			21,547			6,489
Other than income		12,658			11,640			26,565			24,619
		744,593			765,463			1,472,831			1,459,964
OPERATING INCOME		94,201			86,431			171,014			148,361

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		13,113			6,612			25,070			13,179
Interest accrued on deferred energy		457			3,773			1,693			8,387
Carrying charge for Lenzie		-			5,998			-			16,080
Reinstated interest on deferred energy		-			-			-			11,076
Other income		4,532			6,382			18,204			13,688
Other expense		(4,770	)		(8,150	)		(7,797	)		(13,066	)
Income taxes		(4,099	)		(4,675	)		(12,188	)		(16,058	)
		9,233			9,940			24,982			33,286
Total Income Before Interest Charges		103,434			96,371			195,996			181,647

INTEREST CHARGES:
Long-term debt		70,388			68,546			140,343			134,995
Other		7,000			7,445			14,701			15,999
Allowance for borrowed funds used during construction		(10,088	)		(5,374	)		(19,240	)		(10,708	)
		67,300			70,617			135,804			140,286

NET INCOME APPLICABLE TO COMMON STOCK	$	36,134		$	25,754		$	60,192		$	41,361

Amount per share basic and diluted - (Note 7)
Net Income applicable to common stock	$	0.15		$	0.12		$	0.26		$	0.19

Weighted Average Shares of Common Stock Outstanding - basic		233,992,721			221,412,345			233,914,046			221,329,347
Weighted Average Shares of Common Stock Outstanding - diluted		234,519,562			221,821,195			234,420,336			221,738,312

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)
	Six Months Ended
	June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income applicable to common stock	$	60,192		$	41,361
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		126,411			115,911
Deferred taxes and deferred investment tax credit		88,346			31,661
AFUDC		(25,070	)		(13,179	)
Amortization of deferred energy costs - electric		106,821			88,482
Amortization of deferred energy costs - gas		(865	)		638
Deferral of energy costs - electric		(73,464	)		30,941
Deferral of energy costs - gas		896			(638	)
Carrying charge on Lenzie plant		-			(16,080	)
Reinstated interest on deferred energy		-			(11,076	)
Other, net		(10,992	)		15,782
Changes in certain assets and liabilities:
Accounts receivable		(63,653	)		(75,685	)
Materials, supplies and fuel		(2,717	)		(4,460	)
Other current assets		8,929			4,825
Accounts payable		9,690			53,326
Accrued retirement benefits		12,642			5,488
Other current liabilities		11,414			(8,155	)
Risk Management assets and liabilities		(9,837	)		(4,946	)
Other deferred assets		(18,019	)		(14,506	)
Other regulatory assets		(32,812	)		(7,976	)
Other liabilities		178			(17,884	)
Net Cash from Operating Activities		188,090			213,830

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(471,675	)		(585,050	)
Customer advances for construction		(2,297	)		5,254
Contributions in aid of construction		41,994			30,312
Investments and other property - net		4,379			1,381
Net Cash used by Investing Activities		(427,599	)		(548,103	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		428,000			1,029,014
Retirement of long-term debt		(214,070	)		(672,630	)
Sale of common stock		4,795			-
Proceeds from exercise of stock option		-			9,096
Dividends paid		(37,531	)		-
Net Cash from Financing Activities		181,194			365,480

Net Increase (Decrease) in Cash and Cash Equivalents		(58,315	)		31,207
Beginning Balance in Cash and Cash Equivalents		129,140			115,709
Ending Balance in Cash and Cash Equivalents	$	70,825		$	146,916

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	143,472		$	146,941
Income taxes	$	15,553		$	6,824


The accompanying notes are an integral part of the financial statements

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
		June 30,		December 31,
		2008		2007
		(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service		$	5,699,780	$	5,571,492
Less accumulated provision for depreciation			1,426,298		1,407,334
			4,273,482		4,164,158
Construction work-in-progress			716,331		576,127
			4,989,813		4,740,285

Investments and other property, net			19,568		19,544

Current Assets:
Cash and cash equivalents			36,488		37,001
Accounts receivable less allowance for uncollectible accounts:
	2008 - $25,996; 2007-$30,392		339,089		274,242
Deferred energy costs - electric (Note 1)			67,944		75,948
Materials, supplies and fuel, at average cost			67,945		68,671
Risk management assets (Note 5)			221,738		16,078
Intercompany income taxes receivable			43,572		-
Deferred income taxes			-		2,383
Other			25,968		28,352
			802,744		502,675
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			179,718		205,030
Regulatory tax asset			167,899		165,257
Regulatory asset for pension plans			104,214		86,909
Other regulatory assets			540,774		524,460
Risk management assets (Note 5)			43,108		9,069
Risk management regulatory assets - net (Note 5)			-		17,186
Unamortized debt issuance costs			34,416		36,551
Other			108,626		70,403
			1,178,755		1,114,865
TOTAL ASSETS		$	6,990,880	$	6,377,369
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,534,866	$	2,376,740
Long-term debt			2,664,929		2,528,141
			5,199,795		4,904,881
Current Liabilities:
Current maturities of long-term debt			8,636		8,642
Accounts payable			282,060		231,205
Accounts payable, affiliated companies			31,430		32,706
Accrued interest			41,765		41,920
Dividends declared			-		10,907
Accrued salaries and benefits			13,037		16,881
Current income taxes payable			-		3,544
Intercompany income taxes payable			-		15,403
Deferred income taxes			11,478		-
Risk management liabilities (Note 5)			2,085		26,982
Accrued taxes			4,872		4,529
Other current liabilities			71,963		50,902
			467,326		443,621
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			612,223		585,168
Deferred investment tax credit			10,585		11,169
Regulatory tax liability			9,413		10,038
Customer advances for construction			54,921		58,890
Accrued retirement benefits			55,690		25,693
Risk management liabilities (Note 5)			3,323		5,116
Risk management regulatory liability - net (Note 5)			239,796		-
Regulatory liabilities			172,120		168,381
Other			165,688		164,412
			1,323,759		1,028,867

TOTAL CAPITALIZATION AND LIABILITIES		$	6,990,880	$	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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
OPERATING REVENUES:
Electric	$	570,223		$	575,108		$	1,039,395		$	993,273

OPERATING EXPENSES:
Operation:
Purchased power		164,087			175,716			257,837			271,310
Fuel for power generation		209,920			140,773			373,941			304,858
Deferral of energy costs-net		(9,691	)		67,731			36,084			94,663
Other		62,617			55,162			119,712			106,001
Maintenance		13,608			20,319			30,258			37,783
Depreciation and amortization		42,323			38,833			82,953			74,594
Taxes:
Income taxes		12,865			8,654			14,997			442
Other than income		7,427			6,692			15,749			14,426
		503,156			513,880			931,531			904,077
OPERATING INCOME		67,067			61,228			107,864			89,196

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		7,692			3,247			14,550			6,345
Interest accrued on deferred energy		1,084			3,427			2,878			7,276
Carrying charge for Lenzie		-			5,998			-			16,080
Reinstated interest on deferred energy (Note 3)		-			-			-			11,076
Other income		3,107			2,909			8,854			8,030
Other expense		(1,656	)		(5,384	)		(3,017	)		(7,426	)
Income taxes		(3,131	)		(3,553	)		(7,522	)		(14,131	)
		7,096			6,644			15,743			27,250
Total Income Before Interest Charges		74,163			67,872			123,607			116,446

INTEREST CHARGES:
Long-term debt		41,624			41,368			82,621			81,074
Other		5,384			5,603			11,215			12,439
Allowance for borrowed funds used during construction		(6,020	)		(2,703	)		(11,375	)		(5,253	)
		40,988			44,268			82,461			88,260

NET INCOME	$	33,175		$	23,604		$	41,146		$	28,186


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)
	Six Months Ended
	June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	41,146		$	28,186
Adjustments to reconcile net income to net cash from or
operating activities:
Depreciation and amortization		82,953			74,594
Deferred taxes and deferred investment tax credit		18,119			9,826
AFUDC		(14,550	)		(6,345	)
Amortization of deferred energy costs		88,210			64,747
Deferral of energy costs		(54,895	)		23,023
Carrying charge on Lenzie plant		-			(16,080	)
Reinstated interest on deferred energy		-			(11,076	)
Other, net		(8,562	)		2,587
Changes in certain assets and liabilities:
Accounts receivable		(76,989	)		(113,064	)
Materials, supplies and fuel		726			(2,576	)
Other current assets		2,385			(5,292	)
Accounts payable		19,379			65,001
Accrued retirement benefits		7,789			6,983
Other current liabilities		17,405			(6,077	)
Risk management assets and liabilities		(9,406	)		(7,135	)
Other deferred assets		(18,731	)		(10,829	)
Other regulatory assets		(21,859	)		(5,981	)
Other liabilities		1,357			(1,695	)
Net Cash from Operating Activities		74,477			88,797

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(352,560	)		(363,241	)
Customer advances for construction		(3,969	)		3,313
Contributions in aid of construction		33,869			20,289
Investments and other property - net		2,795			1,366
Net Cash used by Investing Activities		(319,865	)		(338,273	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		225,000			569,586
Retirement of long-term debt		(88,218	)		(314,462	)
Additional investment by parent company		133,000			-
Dividends paid		(24,907	)		(13,472	)
Net Cash from Financing Activities		244,875			241,652

Net Increase (Decrease) in Cash and Cash Equivalents		(513	)		(7,824	)
Beginning Balance in Cash and Cash Equivalents		37,001			36,633
Ending Balance in Cash and Cash Equivalents	$	36,488		$	28,809

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	84,783		$	90,847
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)
		June 30,		December 31,
		2008		2007
		(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service		$	2,940,355	$	2,897,219
Less accumulated provision for depreciation			1,136,952		1,119,045
			1,803,403		1,778,174
Construction work-in-progress			532,395		492,539
			2,335,798		2,270,713

Investments and other property, net			438		570

Current Assets:
Cash and cash equivalents			21,829		23,807
Accounts receivable less allowance for uncollectible accounts:
	2008 - $2,560; 2007 - $5,669		125,021		160,014
Materials, supplies and fuel, at average cost			52,235		48,799
Risk management assets (Note 5)			106,046		6,208
Intercompany income taxes receivable			33,276		-
Deferred income taxes			17,686		17,728
Other			10,214		17,255
			366,307		273,811
Deferred Charges and Other Assets:
Regulatory tax asset			96,351		102,591
Regulatory asset for pension plans			78,449		43,778
Other regulatory assets			243,255		233,827
Risk management assets (Note 5)			14,914		3,360
Risk management regulatory assets - net (Note 5)			-		8,881
Unamortized debt issuance costs			18,571		19,976
Other			20,194		19,017
			471,734		431,430
TOTAL ASSETS		$	3,174,277	$	2,976,524
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	998,221	$	1,001,840
Long-term debt			1,261,788		1,084,550
			2,260,009		2,086,390
Current Liabilities:
Current maturities of long-term debt			1,662		101,643
Accounts payable			81,476		94,722
Accounts payable, affiliated companies			11,613		19,288
Accrued interest			15,112		15,750
Dividends declared			-		5,333
Accrued salaries and benefits			11,865		14,830
Intercompany income taxes payable			-		2,479
Risk management liabilities (Note 5)			2,023		12,527
Accrued taxes			4,043		3,542
Deferred energy costs-electric (Note 1)			17,614		17,573
Deferred energy costs - gas (Note 1)			11,400		11,369
Other current liabilities			13,354		15,015
			170,162		314,071
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			276,357		267,801
Deferred investment tax credit			16,823		17,726
Regulatory tax liability			17,488		18,407
Customer advances for construction			42,908		41,235
Accrued retirement benefits			84,829		48,025
Risk management liabilities (Note 5)			1,361		2,253
Risk management regulatory liability - net (Note 5)			113,476		-
Regulatory liabilities			146,838		135,645
Other			44,026		44,971
			744,106		576,063
TOTAL CAPITALIZATION AND LIABILITIES		$	3,174,277	$	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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
OPERATING REVENUES:
Electric	$	236,415		$	245,356		$	486,693		$	498,235
Gas		32,152			31,378			117,746			116,498
		268,567			276,734			604,439			614,733
OPERATING EXPENSES:
Operation:
Purchased power		97,363			86,309			187,469			169,619
Fuel for power generation		60,705			51,285			118,292			115,354
Gas purchased for resale		27,632			19,862			94,528			91,508
Deferral of energy costs - electric - net		(11,695	)		18,770			(3,188	)		32,631
Deferral of energy costs - gas - net		(3,774	)		3,554			(1,571	)		1,609
Other		34,765			35,994			68,270			68,842
Maintenance		7,864			10,314			14,336			16,595
Depreciation and amortization		22,018			20,845			43,458			41,317
Taxes:
Income taxes		3,952			2,686			13,611			11,046
Other than income		5,198			4,902			10,726			10,088
		244,028			254,521			545,931			558,609
OPERATING INCOME		24,539			22,213			58,508			56,124

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,421			3,365			10,520			6,834
Interest accrued on deferred energy		(627	)		346			(1,185	)		1,111
Other income		1,229			3,011			8,964			4,842
Other expense		(2,881	)		(2,191	)		(4,681	)		(4,205	)
Income taxes		(953	)		(1,282	)		(4,527	)		(2,493	)
		2,189			3,249			9,091			6,089
Total Income Before Interest Charges		26,728			25,462			67,599			62,213

INTEREST CHARGES:
Long-term debt		18,578			16,542			37,340			32,650
Other		1,369			1,583			2,991			3,042
Allowance for borrowed funds used during construction		(4,068	)		(2,671	)		(7,865	)		(5,455	)
		15,879			15,454			32,466			30,237

NET INCOME	$	10,849		$	10,008		$	35,133		$	31,976


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)
	Six Months Ended
	June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	35,133		$	31,976
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		43,458			41,317
Deferred taxes and deferred investment tax credit		10,537			(7,652	)
AFUDC		(10,520	)		(6,834	)
Amortization of deferred energy costs - electric		18,611			23,735
Amortization of deferred energy costs - gas		(865	)		638
Deferral of energy costs - electric		(18,569	)		7,918
Deferral of energy costs - gas		896			(638	)
Other, net		2,235			13,216
Changes in certain assets and liabilities:
Accounts receivable		13,330			37,212
Materials, supplies and fuel		(3,437	)		(1,884	)
Other current assets		7,041			10,161
Accounts payable		(11,624	)		15,814
Accrued retirement benefits		826			(2,354	)
Other current liabilities		(4,762	)		(1,119	)
Risk management assets and liabilities		(431	)		2,189
Other deferred assets		712			(3,677	)
Other regulatory assets		(10,953	)		(1,995	)
Other liabilities		215			(2,139	)
Net Cash from Operating Activities		71,833			155,884

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(119,115	)		(221,809	)
Customer advances for construction		1,672			1,941
Contributions in aid of construction		8,125			10,023
Investments and other property - net		1,584			12
Net Cash used by Investing Activities		(107,734	)		(209,833	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		203,000			459,428
Retirement of long-term debt		(125,744	)		(358,062	)
Investment by parent company		20,000			-
Dividends paid		(63,333	)		(6,736	)
Net Cash from Financing Activities		33,923			94,630

Net Increase (Decrease) in Cash and Cash Equivalents		(1,978	)		40,681
Beginning Balance in Cash and Cash Equivalents		23,807			53,260
Ending Balance in Cash and Cash Equivalents	$	21,829		$	93,941

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	38,318		$	34,823
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 six months ended June 30, 2008, are not necessarily indicative of the results to be expected for the full year.

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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 June 30, 2008 (dollars in thousands):

	June 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 pending PUCN approval (1)		(43,699	)		(34,198	)		(10,161	)		(88,058	)
Cumulative balance request in 2008 DEAA		36,225			(20,941	)		(11,369	)		3,915
2008 amortization of approved balances		(69,206	)		(15,765	)		865			(84,106	)
2008 deferred energy costs not yet requested		52,321			18,285			(896	)		69,710
Western Energy Crisis Rate Case - NPC (effective 6/07, 3 years)		55,710			-			-			55,710
Reinstatement of deferred energy (effective 6/07, 10 years)		172,612			-			-			172,612
Cumulative CPUC balance		-			807			-			807
Total	$	247,662		$	(17,614	)	$	(11,400	)	$	218,648

Current Assets
Deferred energy costs – electric	$	67,944		$	-		$	-		$	67,944
Deferred Assets
Deferred energy costs - electric		179,718			-			-			179,718
Current Liabilities
Deferred energy costs – electric		-			(17,614	)		-			(17,614	)
Deferred energy costs – gas		-			-			(11,400	)		(11,400	)
Total	$	247,662		$	(17,614	)	$	(11,400	)	$	218,648

(1)	Credit balances represent potential refunds to the Utilities’ customers.

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.

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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
June 30, 2008	Electric			Electric			Gas			Total			Other			Consolidated

Operating Revenues	$	570,223		$	236,415		$	32,152		$	268,567		$	4		$	838,794

Energy Costs:
Purchased power		164,087			97,363			-			97,363			-			261,450
Fuel for power generation		209,920			60,705			-			60,705			-			270,625
Gas purchased for resale		-			-			27,632			27,632			-			27,632
Deferred energy costs - net		(9,691	)		(11,695	)		(3,774	)		(15,469	)		-			(25,160	)
		364,316			146,373			23,858			170,231			-			534,547

Gross Margin	$	205,907		$	90,042		$	8,294		$	98,336		$	4		$	304,247


Other		62,617									34,765			1,265			98,647
Maintenance		13,608									7,864			-			21,472
Depreciation and amortization		42,323									22,018			-			64,341
Taxes:
Income taxes		12,865									3,952			(3,889	)		12,928
Other than income		7,427									5,198			33			12,658

Operating Income	$	67,067								$	24,539		$	2,595		$	94,201


Six Months Ended	NPC		SPPC			SPPC			SPPC			SPR			SPR
June 30, 2008	Electric		Electric			Gas			Total			Other			Consolidated

Operating Revenues	$	1,039,395	$	486,693		$	117,746		$	604,439		$	11		$	1,643,845

Energy Costs:
Purchased power		257,837		187,469			-			187,469			-			445,306
Fuel for power generation		373,941		118,292			-			118,292			-			492,233
Gas purchased for resale		-		-			94,528			94,528			-			94,528
Deferred energy costs - net		36,084		(3,188	)		(1,571	)		(4,759	)		-			31,325
		667,862		302,573			92,957			395,530			-			1,063,392

Gross Margin	$	371,533	$	184,120		$	24,789		$	208,909		$	11		$	580,453


Other		119,712								68,270			2,340			190,322
Maintenance		30,258								14,336			-			44,594
Depreciation and amortization		82,953								43,458			-			126,411
Taxes:
Income taxes		14,997								13,611			(7,061	)		21,547
Other than income		15,749								10,726			90			26,565

Operating Income	$	107,864							$	58,508		$	4,642		$	171,014

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Three Months Ended	NPC		SPPC		SPPC		SPPC		SPR			SPR
June 30, 2007	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	575,108	$	245,356	$	31,378	$	276,734	$	52		$	851,894

Energy Costs:
Purchased power		175,716		86,309		-		86,309		-			262,025
Fuel for power generation		140,773		51,285		-		51,285		-			192,058
Gas purchased for resale		-		-		19,862		19,862		-			19,862
Deferred energy costs - net		67,731		18,770		3,554		22,324		-			90,055
		384,220		156,364		23,416		179,780		-			564,000

Gross Margin	$	190,888	$	88,992	$	7,962	$	96,954	$	52		$	287,894


Other		55,162						35,994		1,112			92,268
Maintenance		20,319						10,314		-			30,633
Depreciation and amortization		38,833						20,845		-			59,678
Taxes:
Income taxes		8,654						2,686		(4,096	)		7,244
Other than income		6,692						4,902		46			11,640

Operating Income	$	61,228					$	22,213	$	2,990		$	86,431

Six Months Ended	NPC		SPPC		SPPC		SPPC		SPR			SPR
June 30, 2007	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	993,273	$	498,235	$	116,498	$	614,733	$	319		$	1,608,325

Energy Costs:
Purchased power		271,310		169,619		-		169,619		-			440,929
Fuel for power generation		304,858		115,354		-		115,354		-			420,212
Gas purchased for resale		-		-		91,508		91,508		-			91,508
Deferred energy costs - net		94,663		32,631		1,609		34,240		-			128,903
		670,831		317,604		93,117		410,721		-			1,081,552

Gross Margin	$	322,442	$	180,631	$	23,381	$	204,012	$	319		$	526,773


Other		106,001						68,842		2,172			177,015
Maintenance		37,783						16,595		-			54,378
Depreciation and amortization		74,594						41,317		-			115,911
Taxes:
Income taxes		442						11,046		(4,999	)		6,489
Other than income		14,426						10,088		105			24,619

Operating Income	$	89,196					$	56,124	$	3,041		$	148,361

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NOTE 3. REGULATORY ACTIONS

Pending Rate Cases

Nevada Power Company

NPC 2008 Deferred Energy Rate Case and Base Tariff Energy Rate (BTER) Update

In February 2008, NPC filed applications to create a new Deferred Energy Accounting Adjustment (DEAA) rate and to update the going forward BTER. In these applications, NPC requests to decrease rates by $116.3 million, a decrease of 5.04% while recovering $36 million of deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2008 and the going forward BTER became effective April 1, 2008. Hearings on the DEAA portion are scheduled for August 2008.

In May 2008 NPC filed an update to its going forward BTER which decreased rates an additional $11.1 million, resulting in less than a 1% additional decrease. The updated going forward BTER became effective July 1, 2008.

NPC Eighth Amendment to 2006 Integrated Resource Plan (IRP)

In May 2008, NPC filed its eighth amendment to its IRP. Significant requests in the eighth amendment include:

Several approvals related to the Ely Energy Center (“EEC”): first, to delay the required 2008 EEC Amendment filing to no later than April 2010; second, to update the budget for the development and permitting of EEC ($155 million through February 2010); and third, to revise the proposed EEC construction schedule to accommodate a June 1, 2015 in-service date for Unit 1 and June 1, 2016 in-service date for Unit 2 (implicit in this request is the continued operation of the Reid Gardner Units 1-3 through 2016).

·	Approval to purchase 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.

Approval to construct 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 amendment requests approval to establish a regulatory asset for the plant and related operations and maintenance costs, depreciation and return on the plant until such time it is included in rates.

Approval of various electric transmission projects at a total estimated cost of $220 million, the majority of which is the Sunrise 500 kV Tap project with a scheduled commercial operation date of 2011 and a total estimated cost of $182 million (not including previously purchased land and land rights).

Hearings for the eighth amendment will be held in September with a decision expected by mid-October.

NPC Ninth Amendment to its 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 Carson Lake Project and related operating and maintenance costs, depreciation and return on the plant, until such time it is included in general rates.

Sierra Pacific Power Company

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 requests 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 new DEAA rate will be effective October 1, 2008 and the going forward BTER became effective April 1, 2008. Hearings for the DEAA portion are scheduled for August 2008.

In May 2008, SPPC filed an update to its going forward BTER which decreased rates an additional $5.2 million, resulting in an additional 3% decrease. The updated going forward BTER became effective July 1, 2008.

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 requests 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 new DEAA rate will be effective October 1, 2008 and the going forward BTER became effective April 1, 2008.

In May 2008 SPPC filed an update to its going forward BTER which decreased rates less than $500 thousand resulting in a less than 1% additional decrease. The updated going forward BTER became effective July 1, 2008.

SPPC Nevada Electric Third Amendment to 2007 Integrated Resource Plan (IRP)

In May 2008, SPPC filed a third amendment to its IRP. Similar to NPC, SPPC updated several items related to the EEC, as discussed above. Hearings on the third amendment will be held in September with a decision expected by mid-October.

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 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 Rate Cases

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 will be effective September 1, 2008.

NPC Seventh Amendment to its IRP

In March 2008, NPC filed its seventh amendment to its 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, providing a minimum of 30 megawatts (MW) 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.

·	Approval to construct the 6 MW 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.

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.

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SPPC Nevada 2007 General Rate Case

In December 2007, SPPC filed its statutorily required electric general rate case (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 combined cycle generating plant; and

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

NPC Fifth Amendment to 2006 Integrated Resource Plan (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.

SPPC Nevada 2003 General Rate Case

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 (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 its January 25, 2006 order, remanded the matter back to the PUCN for further review.

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 six months ended June 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.

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NOTE 4. LONG-TERM DEBT

As of June 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	$	3,614		$	1,062	$	-	$	4,676
2009		22,218			600		-		22,818
2010		148,004			178,000		-		326,004
2011		369,924			-		-		369,924
2012		136,448			100,000		63,670		300,118
		680,208			279,662		63,670		1,023,540
Thereafter		2,005,750			973,250		460,539		3,439,539
		2,685,958			1,252,912		524,209		4,463,079
Unamortized Premium(Discount) Amount		(12,393	)		10,538		855		(1,000	)
Total	$	2,673,565		$	1,263,450	$	525,064	$	4,462,079

The preceding table includes obligations related to capital lease obligations discussed under lease commitments within this note. Substantially all utility plant is subject to the liens of NPC’s and SPPC’s indentures under which their respective General and Refunding Mortgage bonds are issued.

Financing Transactions

Nevada Power Company

General and Refunding Mortgage Notes, Series S

On July 31, 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 its 9.00% General and Refunding Mortgage Notes, Series G, for approximately $17.2 million. The notes are scheduled to be redeemed on August 15, 2008, at 104.50% of the stated principal amount, plus accrued interest to the date of redemption. NPC intends to use 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 will remain the sole holder of the Bonds. 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.

Sierra Pacific Power Company

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 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. 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.

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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 derivatives 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 purchase 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 under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value.

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 models 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.

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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 has minimal 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):

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

Risk management assets- current	$	327.8	$	221.7	$	106.1	$	22.3		$	16.1		$	6.2
Risk management assets- noncurrent		58.0		43.1		14.9		12.5			9.1			3.4
Total risk management assets		385.8		264.8		121.0		34.8			25.2			9.6

Risk management liabilities- current		4.1		2.1		2.0		39.5			27.0			12.5
Risk management liabilities- noncurrent		4.7		3.3		1.4		7.4			5.1			2.3
Total risk management liabilities		8.8		5.4		3.4		46.9			32.1			14.8

Less prepaid electric and gas options		23.7		19.6		4.1		13.9			10.2			3.7

Risk management regulatory assets/liabilities – net (1)	$	353.3	$	239.8	$	113.5	$	(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 in SFAS 133, 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 increase of risk management assets as of June 30, 2008, as compared to December 31, 2007, is mainly due to favorable derivative positions on natural gas options held by the Utilities to hedge energy price risk for their customers resulting from higher commodity prices for natural gas at June 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.

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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 June 30, 2008 is approximately $45 million. Additional expenditures through 2010 are projected to be approximately $2.8 million, for a total expenditure of approximately $47.8 million.

Over the last two years, 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.

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).

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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 refilling 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.

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 June 30, 2008, NPC has a $17.4 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.

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 six months ended June 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 six months ended June 30, 2008.

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Sierra Pacific Power Company

Farad Dam

SPPC owns four hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the flume and dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs. In May 2005, Insurers filed a motion for summary judgment on the coverage issue, which has been denied. In October 2005, Insurers filed another partial summary judgment motion with respect to coverage, which the court also denied. On June 16, 2006, Insurers filed new summary judgment motions, which SPPC opposed. The Court denied the motions and asked parties to brief the Court on certain insurance coverage issues involving timing and cost recovery associated with rebuilding the dam. The case went to trial in April 2008. NPC filed post-trial briefs in May 2008 and a decision is expected in the summer of 2008. Management has not recorded a loss contingency for this matter, because the loss, if any, cannot be estimated at this time .

Regulatory Contingencies

The Utilities have begun various construction projects and entered into related construction contracts for which PUCN approval has not been previously obtained. While management believes the costs to be prudent and necessary to meet future electricity demand, in the event all or a portion of these project costs were disallowed by the PUCN, the Utilities may be required to evaluate these assets for impairment which could have a material effect on the future financial position, results of operations and cash flows of SPR, NPC and SPPC.

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.

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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 June 30,				Six months ended June 30,
	2008		2007		2008		2007
Basic EPS
Numerator ($000)

Net income applicable to common stock	$	36,134	$	25,754	$	60,192	$	41,361

Denominator
Weighted average number of common shares outstanding		233,992,721		221,412,345		233,914,046		221,329,347

Per Share Amounts

Net income applicable to common stock	$	0.15	$	0.12	$	0.26	$	0.19

Diluted EPS
Numerator ($000)

Net income applicable to common stock	$	36,134	$	25,754	$	60,192	$	41,361

Denominator (1)
Weighted average number of shares outstanding before dilution		233,992,721		221,412,345		233,914,046		221,329,347
Stock options		57,533		146,350		59,142		149,103
Non-Employee Director stock plan		56,987		44,613		56,650		42,639
Employee stock purchase plan		871		4,471		436		3,807
Restricted Shares		5,247		-		3,279		-
Performance Shares		406,203		213,416		386,783		213,416
		234,519,562		221,821,195		234,420,336		221,738,312

Per Share Amounts

Net income applicable to common stock	$	0.15	$	0.12	$	0.26	$	0.19

(1)

The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan for the three and six months ended June 30, 2008 and 2007, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the three and six months ended June 30, 2008, 972,761 and 941,278 shares, respectively, would be included and 581,074 and 727,949 shares, respectively, would be included for the three and six months ended June 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 and six months ended June 30 follows. This summary is based on a September 30 measurement date (dollars in thousands):

Sierra Pacific Resources, consolidated

	For the Three Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	5,247		$	5,725		$	716		$	768
Interest cost		10,675			9,855			3,148			2,570
Expected return on plan assets		(11,463	)		(10,474	)		(2,144	)		(1,309	)
Amortization of prior service cost		(118	)		407			234			30
Amortization of net (gain)/loss		1,981			1,803			855			242
Amortization of transition obligation		-			-			-			815

Net periodic benefit cost	$	6,322		$	7,316		$	2,809		$	3,116


	For the Six Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	11,270		$	11,450		$	1,281		$	1,536
Interest cost		21,465			19,710			5,366			5,140
Expected return on plan assets		(24,124	)		(20,948	)		(4,175	)		(2,618	)
Amortization of prior service cost		290			814			(514	)		61
Amortization of net (gain)/loss		2,752			3,606			1,744			484
Amortization of transition obligation		-			-			-			1,629

Net periodic benefit cost	$	11,653		$	14,632		$	3,702		$	6,232

Nevada Power Company
	For the Three Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	3,062		$	3,273		$	313		$	244
Interest cost		5,257			4,744			707			510
Expected return on plan assets		(5,496	)		(4,750	)		(671	)		(291	)
Amortization of prior service cost		1			358			399			29
Amortization of net (gain)/loss		981			857			186			160
Amortization of transition obligation		-			-			-			227

Net periodic benefit cost	$	3,805		$	4,482		$	934		$	879

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	For the Six Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	6,612		$	6,546		$	608		$	519
Interest cost		10,610			9,488			1,262			1,085
Expected return on plan assets		(11,562	)		(9,500	)		(1,351	)		(619	)
Amortization of prior service cost		363			715			579			61
Amortization of net (gain)/loss		1,357			1,715			404			341
Amortization of transition obligation		-			-			-			484

Net periodic benefit cost	$	7,380		$	8,964		$	1,502		$	1,871

Sierra Pacific Power Company
	For the Three Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	1,939		$	2,138		$	384		$	452
Interest cost		5,063			4,775			2,401			1,839
Expected return on plan assets		(5,668	)		(5,492	)		(1,438	)		(886	)
Amortization of prior service cost		(64	)		53			(169	)		-
Amortization of net (gain)/loss		920			867			659			585

Net periodic benefit cost	$	2,190		$	2,341		$	1,837		$	1,990

	For the Six Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	4,117		$	4,276		$	638		$	987
Interest cost		10,149			9,550			4,027			4,021
Expected return on plan assets		(11,933	)		(10,984	)		(2,756	)		(1,937	)
Amortization of prior service cost		(12	)		106			(1,101	)		-
Amortization of net (gain)/loss		1,256			1,734			1,317			1,278

Net periodic benefit cost	$	3,577		$	4,682		$	2,125		$	4,349

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, 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 attributable to the three-month period from September 30, 2007 to December 31, 2007.

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 June 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.

As previously disclosed in Note 11, Retirement Plan and Post-retirement Benefits, in the 2007 Form 10-K, expected contributions for 2008 are $1.9 million for the pension plan and $0.4 million for other postretirement benefits. Management will continue to re-assess the amounts to be funded for each of the plans in 2008, after final funding rules are adopted by the Internal Revenue Service.

NOTE 9. DIVIDENDS

On February 7, 2008, SPR’s Board of Directors declared a quarterly cash dividend 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, payable on September 10, 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, particularly in Southern Nevada, including inflation rates, monetary policy, customer bankruptcies, weaker housing markets and a decrease in tourism 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, 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 unfavorable rulings by the Public Utilities Commission of Nevada (PUCN), untimely regulatory approval for such 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 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)

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;

(6)

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;

(7)	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;

(8)

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), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

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

(10)

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;

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

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

(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 Indian gaming establishments in California and other states; and

(17)	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), and includes 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 the Utilities.

For the three months ended June 30, 2008, SPR recognized net income applicable to common stock of $36.1 million compared to $25.8 million for the same period in 2007. For the six months ended June 30, 2008, SPR recognized net income applicable to common stock of $60.2 million compared to $41.4 million for the same period in 2007. See SPR’s, NPC’s and SPPC’s respective Results of Operations for more details on the increase 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, Southern Nevada has experienced decreased activity in the real estate and tourism markets. Additionally on August 1, 2008, Boyd Gaming announced the delay of the partially built Echelon Project, a $4.8 billion, 5,000 room, hotel and casino in Las Vegas, which was scheduled to open in 2010. According to its press release, Boyd Gaming plans to resume construction in three or four quarters, assuming credit market conditions and the economic outlook improves. However, due to the current economic conditions in Las Vegas, management is focusing on our assessments, strategies and projections for factors such as growth, load forecasts, capital expenditures, rising fuel costs, access to capital markets, collections on accounts receivable and counterparty risk among other factors.

In the Western and Southwestern portions of the United States, energy needs continue to increase; however, the development of generating facilities by utility companies has decreased. As a result, the cost of energy and natural gas continues to rise 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.

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

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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 over the next three years 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 April 2008, the Utilities filed their 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 $457 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.

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’ April 2008 Portfolio Standard Annual Report for Compliance Year 2007 (submitted to the PUCN jointly), 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.

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, if approval is obtained from the PUCN. 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.

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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.

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 August 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.

On April 22, 2008, NPC announced its intention to purchase the 598 MW (nominally rated), natural gas fired combined cycle power plant, the Bighorn Power Plant, from Reliant Resources, Inc., for approximately $510 million, including costs for inventory and other closing costs and adjustments. NPC expects the final acquisition to occur later in 2008 following required reviews and approvals from various regulatory authorities, including the PUCN. As a result of the potential acquisition of the Bighorn Power Plant, NPC resubmitted its 7th amendment to its IRP as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements and filed an 8th amendment to its IRP in May 2008. The requested approval of the Harry Allen and Sunrise 500 kV TAP projects and the update of the Ely Energy Center, which were originally in the 7th amendment, are now included in the 8th amendment along with a request to approve the acquisition of the Bighorn Power Plant. Additionally, SPPC resubmitted its 2nd amendment to its IRP, as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements and filed a 3rd amendment to its IRP in May 2008, which addresses the update of the Ely Energy Center that was originally in the 2nd amendment.

Management of Energy Risk

Entering 2008, the Utilities expect to 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.

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 . In the next five years, NPC is projected to spend $214.3 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.

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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. Major projects included in the Utilities’ IRPs include the Ely Energy Center, Tracy Generating Station, the Bighorn Power Plant, and Clark Station. 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 expected 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

A significant focus in 2008 will again be to generate 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. However, significant amounts of capital may be necessary to fund existing and prospective construction projects, as well as volatile energy costs. As a result of slower growth, the potential acquisition of Bighorn and the timing of certain projects, management has reduced the Utilities’ 2008 estimated cash construction requirement of $1.2 billion, which includes funds invested through June 30, 2008, by approximately $100 - $150 million for the remainder of 2008. Additionally, the Utilities intend to reduce 2009 estimated cash construction requirements by $100 - $150 million. As a result, the Utilities’ estimated cash requirement for the years 2008-2012 is approximately $7.4 billion for capital projects, some of which include: the Ely Energy Center for $2.4 billion (does not include costs beyond 2012), Tracy for $30.1 million, Clark Station for $120.3 million, Harry Allen for $681.9 million, renewable development of $457 million and environmental upgrades of $214.3 million. Of these major projects, approximately $930 million has been approved by the PUCN. In addition, pending regulatory approval of the acquisition of the Bighorn Power Plant, cash requirements for 2008 will increase by approximately $510 million, including costs for inventory and other closing costs and adjustments. 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.

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 $20.9 million and $21.8 million of interest costs for the six months ended June 30, 2008 and 2007 respectively.

During the three months ended June 30, 2008, SPR recognized net income applicable to common stock of approximately $36.1 million compared to $25.8 million to the same period in 2007. The increase was primarily due to an increase in operating income and an increase in AFUDC, as a result of the construction of the Clark Peaking Units and the expansion of the Tracy Generating Station. Operating income increased primarily due to an increase in NPC’s Base Tariff General Rates (BTGR), as a result of NPC’s 2006 GRC, effective June 1, 2007.

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During the six months ended June 30, 2008, SPR recognized net income applicable to common stock of approximately $60.2 million compared to $41.4 million to the same period in 2007. The increase was primarily due to the items noted above and the reinstatement of disallowed plant costs related to Piñon Pine, as discussed further in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. Partially offsetting this increase was 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 June 30, 2008 NPC had paid $24.9 million in dividends to SPR and SPPC had paid $63.3 million in dividends to SPR. On August 4, 2008, NPC declared an additional $30.0 million dividend to SPR. On August 4, 2008, SPPC declared an additional $15.0 million dividend to SPR.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the six months ended June 30, 2008 compared to the same period in 2007 due to decreases in cash from operating and financing activities, partially offset by a decrease in cash used by investing 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 June 2007 rate increase resulting from NPC’s GRC, the settlement with Calpine, and prepaid transmission revenues.

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 decreased due to reduced debt financings and 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 June 30, 2008 (in millions)
	SPR		NPC		SPPC
Cash and Cash Equivalents	$	12.2	$	36.5	$	21.8
Balance available on Revolving Credit Facility		N/A		456.3		153.2
	$	12.2	$	492.8	$	175.0

In addition to cash on hand and the Utilities’ revolving credit facilities, the Utilities may issue debt up to $1.3 billion 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 requirement, SPR and the Utilities may use hedging activities. However, 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.

SPR has approximately $40.7 million payable of debt service obligations for 2008, of which $20.4 million was paid in the six months ended June 30, 2008. SPR intends to pay the remaining interest payments through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below).

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During the six months ended June 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.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of June 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 June 30, 2008, SPR, NPC, SPPC and their subsidiaries had approximately $4.5 billion of debt and other obligations outstanding, consisting of approximately $2.7 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 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 currently pay dividends to SPR out of earnings and are therefore not affected by this provision. Moreover, 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 Utilities experienced a material loss and/or the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

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 August 1, 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.

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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 actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of the Utilities' auction rate securities of approximately $556 million as of June 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 issues underlying rating and the Insurer's rating. As of June 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 six 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 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 June 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 June 30, 2008, SPR would be allowed to incur up to $1.3 billion of additional indebtedness on a consolidated basis.

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 June 30, 2008, NPC had approximately $1.6 billion of PUCN financing authority.

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The financial covenants under NPC’s debt allow for greater borrowings than SPR’s cap on additional indebtedness; therefore, NPC is limited by SPR’s cap on additional indebtedness of $1.3 billion.

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 $1.3 billion, 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 June 30, 2008, $2.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue an additional $882 million of General and Refunding Mortgage Securities as of June 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 June 30, 2008, SPPC had approximately $745 million of PUCN financing authority.

The financial covenants under SPPC’s debt limit SPPC’s borrowing to approximately $839.0 million as of June 30, 2008, therefore, SPPC is not limited by SPR’s cap on additional indebtedness of $1.3 billion.

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”).

As of June 30, 2008, $1.4 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue an additional $480 million of General and Refunding Mortgage Securities as of June 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.

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NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $33.2 million during the three months ended June 30, 2008 compared to net income of $23.6 million for the same period in 2007. During the six months ended June 30, 2008, NPC recognized net income of approximately $41.1 million compared to net income of approximately $28.2 million for the same period in 2007.

During the six months ended June 30, 2008, NPC paid $24.9 million in dividends to SPR. On August 4, 2008, NPC declared an additional $30.0 million dividend 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.

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

	Three Months Ended June 30,								Six Months Ended June 30,
						Change from							Change from
	2008			2007		Prior Year %			2008		2007		Prior Year %
Operating Revenues:
Electric	$	570,223		$	575,108		-0.8	%	$	1,039,395	$	993,273		4.6	%


Energy Costs:
Purchased power		164,087			175,716		-6.6	%		257,837		271,310		-5.0	%
Fuel for power generation		209,920			140,773		49.1	%		373,941		304,858		22.7	%
Deferral of energy costs-net		(9,691	)		67,731		-114.3	%		36,084		94,663		-61.9	%
	$	364,316		$	384,220		-5.2	%	$	667,862	$	670,831		-0.4	%


Gross Margin	$	205,907		$	190,888		7.9	%	$	371,533	$	322,442		15.2	%

Gross margin increased for the three and six months ended June 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. Partially offsetting the increase was a decrease in use per customer primarily due to cooler weather and a change in customer usage patterns.

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

Electric Operating Revenue

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %
Electric Operating Revenues:
Residential	$	245,810	$	267,060		-8.0	%	$	451,188	$	446,309		1.1	%
Commercial		123,947		122,130		1.5	%		228,459		218,033		4.8	%
Industrial		176,778		167,520		5.5	%		309,789		292,346		6.0	%
Retail revenues		546,535		556,710		-1.8	%		989,436		956,688		3.4	%
Other		23,688		18,398		28.8	%		49,959		36,585		36.6	%
Total Revenues	$	570,223	$	575,108		-0.8	%	$	1,039,395	$	993,273		4.6	%

Retail sales in thousands
Of megawatt-hours (MWh)		5,245		5,588		-6.1	%		9,539		9,782		-2.5	%

Average retail revenue per MWh	$	104.20	$	99.63		4.6	%	$	103.72	$	97.80		6.1	%

NPC’s retail revenues decreased for the three months ended June 30, 2008 as compared to the same period in 2007 due to a decrease in customer usage due to cooler weather and a change in customer usage patterns. Partially offsetting the decrease in revenues was an increase in retail rates and customer count. Retail rates increased as a result of NPC’s various Base Tariff Energy Rate (BTER), Deferred Energy Cases and NPC’s 2006 GRC, effective June 1, 2007 (see Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2007 Form 10-K). Average residential, commercial and industrial customers increased by 0.7%, 2.6% and 3.6%, respectively, for the three months ended June 30, 2008.

NPC’s retail revenues increased for the six months ended June 30, 2008 as compared to the same period in 2007 due to increases in retail rates and customer count. Retail rates increased as a result of NPC’s various BTER, Deferred Energy Cases and NPC’s 2006 GRC, effective June 1, 2007 (see Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2007 Form 10-K). Average residential, commercial and industrial customers increased by 1.1%, 3.1% and 3.4%, respectively. These increases were partially offset by a decrease in customer usage due to cooler weather and a change in customer usage patterns.

Electric Operating Revenues – Other increased for the three and six months ended June 30, 2008, compared to the same periods 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, and an increase in transmission revenue as a result of the completion of the Harry Allen to Mead transmission line.

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

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	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Energy Costs	$	374,007	$	316,489		18.2	%	$	631,778	$	576,168		9.7	%
Total System Demand		5,617		5,925		-5.2	%		10,149		10,486		-3.2	%
Average cost per MWH	$	66.58	$	53.42		24.6	%	$	62.25	$	54.95		13.3	%

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

Purchased Power

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Purchased Power	$	164,087	$	175,716		-6.6	%	$	257,837	$	271,310		-5.0	%

Purchased Power in thousands
of MWhs		1,833		2,369		-22.6	%		3,029		3,552		-14.7	%
Average cost per MWh of
purchased power	$	89.52	$	74.17		20.7	%	$	85.12	$	76.38		11.4	%

Purchased power costs and MWhs decreased for the three and six months ended June 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 for the three and six months ended June 30, 2008, increased primarily due to higher natural gas prices slightly offset by a decrease in fixed capacity charges and cost of hedging instruments.

Fuel For Power Generation

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Fuel for power generation	$	209,920	$	140,773		49.1	%	$	373,941	$	304,858		22.7	%

Thousands of MWhs generated		3,784		3,556		6.4	%		7,120		6,934		2.7	%
Average cost per MWh of
generated power	$	55.48	$	39.59		40.1	%	$	52.52	$	43.97		19.4	%

Fuel for power generation costs and the average cost per MWh increased for the three and six months ended June 30, 2008 primarily due to higher natural gas prices partially offset by a decrease in the cost of hedging instruments.

Deferral of Energy Costs - Net

	Three Months Ended June 30,								Six Months Ended June 30,
	2008			2007		Change from Prior Year %			2008		2007		Change from Prior Year %

Deferred energy costs - net	$	(9,691	)	$	67,731		-114.3	%	$	36,084	$	94,663		-61.9	%

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

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Amounts for the three months ended June 30, 2008 and 2007 include amortization of deferred energy costs of $48.4 million and $40.6 million, respectively; and an under-collection of amounts recoverable in rates of $58.1 million in 2008 and an over-collection of $27.1 million in 2007. Amounts for the six months ended June 30, 2008 and 2007 include amortization of deferred energy costs of $88.2 million and $64.7 million, respectively; and an under-collection of amounts recoverable in rates of $52.1 million in 2008 and an over-collection of $29.9 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 June 30,							Six Months Ended June 30,
	2008		2007		Change from Prior Year %			2008		2007		Change from Prior Year %

Allowance for other funds
used during construction	$	7,692	$	3,247		136.9	%	$	14,550	$	6,345		129.3	%

Allowance for borrowed funds used during construction	$	6,020	$	2,703		122.7	%	$	11,375	$	5,253		116.5	%
	$	13,712	$	5,950		130.5	%	$	25,925	$	11,598		123.5	%

AFUDC increased for the three and six months ended June 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.

Other (Income) and Expenses

	Three Months Ended June 30,									Six Months Ended June 30,
	2008			2007			Change from Prior Year %			2008			2007			Change from Prior Year %

Other operating expense	$	62,617		$	55,162			14	%	$	119,712		$	106,001			13	%
Maintenance expense	$	13,608		$	20,319			-33	%	$	30,258		$	37,783			-19.9	%
Depreciation and amortization	$	42,323		$	38,833			9.0	%	$	82,953		$	74,594			11.2	%
Interest charges on long-term debt	$	41,624		$	41,368			0.6	%	$	82,621		$	81,074			1.9	%
Interest charges-other	$	5,384		$	5,603			-3.9	%	$	11,215		$	12,439			-9.8	%
Interest accrued on deferred energy	$	(1,084	)	$	(3,427	)		-68.4	%	$	(2,878	)	$	(7,276	)		-60.4	%
Carrying charge for Lenzie		-		$	(5,998	)		N/A			-		$	(16,080	)		N/A
Reinstated interest on deferred energy		-			-			N/A			-		$	11,076			N/A
Other income	$	(3,107	)	$	(2,909	)		6.8	%	$	(8,854	)	$	(8,030	)		10.3	%
Other expense	$	1,656		$	5,384			-69.2	%	$	3,017		$	7,426			-59.4	%

Other operating expense increased for the three and six months ended June 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 as compared to the same period in 2007.

Maintenance expense decreased for the three and six months ended June 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 increased during the three months and six months ended June 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.

Interest charges on Long-Term Debt increased for the three months and six months ended June 30, 2008, as compared to the same period in 2007, due primarily to higher interest rates on variable rate debt. See Note 6, 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.

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

Interest accrued on deferred energy costs decreased for the three months and six months ended June 30, 2008, as compared to the same period in 2007, 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.

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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 and six months ended June 30, 2008, as compared to the same period in 2007, due to a 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 Condensed Notes to Financial Statements. This income was partially offset by lower interest income in 2008.

Other expense decreased during the three months and six months ended June 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 10-K.

ANALYSIS OF CASH FLOWS

Cash flows increased during the six months ended June 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.

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 an increase in general rates in 2007 resulting from NPC’s GRC, the settlement with Calpine and prepaid transmission revenues.

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 slightly primarily due to $133 million of additional investment by SPR, offset by reduced debt issuances and increased dividend payments.

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 June 30, 2008 (in millions)

Cash and Cash Equivalents	$	36.5
Balance available on Revolving Credit Facility (1)	$	456.3

	$	492.8

1 As of August 4, 2008, NPC had approximately $596.3 million available under its revolving credit facility.

In addition to cash on hand and the revolving credit facility, NPC may issue debt up to $1.3 billion on a consolidated basis, subject to certain limitations discussed below.

For the six months ended June 30, 2008, SPR contributed capital to NPC of approximately $133 million for general corporate purposes. For the six months ended June 30, 2008, NPC paid dividends to SPR of $24.9 million. On August 4, 2008, NPC declared an additional $30.0 million dividend to SPR.

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 requirement, NPC may use hedging activities. However, 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. Additionally, a portion of the revolving credit facility may be used to fund the acquisition of the Bighorn Power Plant from Reliant Resources, Inc, if approved.

During the six months ended June 30, 2008, there were no material changes to contractual obligations as set forth in NPC’s 2007 Form 10-K. However, in April 2008, NPC entered into a Purchase Agreement with Reliant Resources, for a 598 MW (nominally rated), natural gas fired combined cycle facility, for approximately $510 million. The agreement is expected to be consummated by the end of 2008 pending various regulatory approvals. In June 2008, NPC entered into an equipment contract for approximately $43.5 million related to Harry Allen.

Financing Transactions

General and Refunding Mortgage Notes, Series S

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 will remain the sole holder of the Bonds. 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 June 30, 2008, NPC was in compliance with these covenants.

Ability to Issue Debt

The financial covenants under NPC’s debt allow for greater borrowings than SPR’s cap on additional indebtedness; therefore, NPC is limited by SPR’s cap on additional indebtedness of $1.3 billion.

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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 August 1, 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+

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 actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of NPC’s auction rate securities of approximately $207.5 million, as of June 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 issues underlying rating and the Insurer's rating. As of June 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 first six months of 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 set during the second quarter 2008, ranging from a low of 4.16% to a high of 8.66%, and a low of 3.25 % to a high of 8.66% for the six months ended June 30, 2008, with a weighted average interest rate of 5.93% for the six months ended June 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.

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SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $10.8 million for the three months ended June 30, 2008 compared to net income of $10.0 million for the same period in 2007. During the six months ended June 30, 2008, SPPC recognized net income of approximately $35.1 million compared to $32.0 million for the same period in 2007.

During the six months ended June 30, 2008, SPPC paid $63.3 million in dividends to SPR. On August 4, 2008, SPPC declared a dividend to SPR of $15.0 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.

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

	Three Months Ended June 30,								Six Months Ended June 30,
						Change from								Change from
	2008			2007		Prior Year %			2008			2007		Prior Year %
Operating Revenues:
Electric	$	236,415		$	245,356		-3.6	%	$	486,693		$	498,235		-2.3	%
Gas		32,152			31,378		2.5	%		117,746			116,498		1.1	%
	$	268,567		$	276,734		-3.0	%	$	604,439		$	614,733		-1.7	%

Energy Costs:
Purchased power		97,363			86,309		12.8	%		187,469			169,619		10.5	%
Fuel for power generation		60,705			51,285		18.4	%		118,292			115,354		2.5	%
Deferral of energy costs-electric-net		(11,695	)		18,770		-162.3	%		(3,188	)		32,631		-109.8	%
Gas purchased for resale		27,632			19,862		39.1	%		94,528			91,508		3.3	%
Deferral of energy costs-gas-net		(3,774	)		3,554		-206.2	%		(1,571	)		1,609		-197.6	%
	$	170,231		$	179,780		-5.3	%	$	395,530		$	410,721		-3.7	%

Energy Costs by Segment:
Electric	$	146,373		$	156,364		-6.4	%	$	302,573		$	317,604		-4.7	%
Gas		23,858			23,416		1.9	%		92,957			93,117		-0.2	%
	$	170,231		$	179,780		-5.3	%	$	395,530		$	410,721		-3.7	%

Gross Margin by Segment:
Electric	$	90,042		$	88,992		1.2	%	$	184,120		$	180,631		1.9	%
Gas		8,294			7,962		4.2	%		24,789			23,381		6.0	%
	$	98,336		$	96,954		1.4	%	$	208,909		$	204,012		2.4	%

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

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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 June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %
Electric operating revenues:
Residential	$	70,289	$	70,347		-0.1	%	$	160,168	$	158,356		1.1	%
Commercial		93,060		95,872		-2.9	%		180,731		182,872		-1.2	%
Industrial		62,996		71,433		-11.8	%		128,779		141,874		-9.2	%
Retail revenues		226,345		237,652		-4.8	%		469,678		483,102		-2.8	%
Other 1		10,070		7,704		30.7	%		17,015		15,133		12.4	%
Total revenues	$	236,415	$	245,356		-3.6	%	$	486,693	$	498,235		-2.3	%

Retail sales in thousands
of megawatt-hours (MWh)		2,047		2,088		-2.0	%		4,197		4,238		-1.0	%

Average retail revenue per MWh	$	110.57	$	113.82		-2.9	%	$	111.91	$	113.99		-1.8	%

Retail revenues decreased for the three and six months ended June 30, 2008 as compared to the same period in 2007 primarily due to decreases in retail rates, lower industrial revenue and to a lesser extent a decrease in customer usage. Retail rates decreased as a result of SPPC’s quarterly BTER updates. For details see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2007 Form 10-K. Industrial revenues decreased primarily due to a new retail service agreement with Newmont Mining Corporation (Newmont) and the transition of two large industrial customers to distribution only service and standby service during the second quarter of 2007. These decreases were partially offset by increased customer count. The average number of residential, commercial and industrial customers increased by 0.5%, 2.2% and 2.4%, respectively, for the three months ended June 30, 2008. The average number of residential, commercial and industrial customers increased by 0.9%, 2.4% and 2.0% respectively for the six months ended June 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 its 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 increased for the three and six months ended June 30, 2008 as compared to the same period in 2007 primarily due to the increased transmission revenue.

Gas Operating Revenues

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %
Gas operating revenues:
Residential	$	18,057	$	17,496		3.2	%	$	68,805	$	65,208		5.5	%
Commercial		8,475		8,492		-0.2	%		32,884		31,839		3.3	%
Industrial		3,866		3,706		4.3	%		11,853		11,005		7.7	%
Retail revenues		30,398		29,694		2.4	%		113,542		108,052		5.1	%
Wholesale revenue		1,126		1,063		5.9	%		2,804		6,979		-59.8	%
Miscellaneous		628		621		1.1	%		1,400		1,467		-4.6	%
Total revenues	$	32,152	$	31,378		2.5	%	$	117,746	$	116,498		1.1	%

Retail sales in thousands
of decatherms		2,407		2,191		9.9	%		9,189		8,479		8.4	%

Average retail revenue per decatherm	$	12.63	$	13.55		-6.8	%	$	12.36	$	12.74		-3.0	%

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SPPC’s retail gas revenues increased for the three and six months ended June 30, 2008 as compared to the same period in the prior year primarily due to colder temperatures and retail customer growth in 2008. The average number of retail customers increased by 1.7% and 1.5% for the three and six months ended June 2008, respectively. 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. 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.

Wholesale revenue for the three month period ended June 30, 2008 was comparable to the same period in 2007. However, wholesale revenues for the six months ended June 30, 2008, decreased compared to the same period in 2007 primarily due to decreased availability of gas for wholesale sales during the first quarter of 2008.

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 June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Energy Costs	$	158,069	$	137,594		14.9	%	$	305,761	$	284,973		7.3	%
Total System Demand		2,247		2,258		-0.5	%		4,532		4,541		-0.2	%
Average cost per MWH	$	70.35	$	60.94		15.4	%	$	67.47	$	62.76		7.5	%

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

Purchased Power

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Purchased power	$	97,363	$	86,309		12.8	%	$	187,469	$	169,619		10.5	%

Purchased power in thousands
of MWhs		1,391		1,450		-4.1	%		2,684		2,780		-3.5	%
Average cost per MW of
purchased power	$	69.99	$	59.52		17.6	%	$	69.85	$	61.01		14.5	%

Purchased Power costs and the average cost per MWh increased for the three and six months ended June 30, 2008 as compared to the same period in 2007 primarily due to higher natural gas prices. The volume of MWhs decreased for the three and six months ended June 30, 2008 as compared to the same period in 2007 primarily due to increased reliance on internal generation.

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Fuel for Power Generation

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %

Fuel for power generation	$	60,705	$	51,285		18.4	%	$	118,292	$	115,354		2.5	%

Thousands of MWh generated		856		808		5.9	%		1,848		1,761		4.9	%
Average fuel cost per MWh
of generated power	$	70.92	$	63.47		11.7	%	$	64.01	$	65.50		-2.3	%

Fuel for power generation and average cost per MWh increased for the three months ended June 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.

Fuel for power generation increased for the six months ended June 30, 2008 as compared to the same period in 2007 due to higher natural gas prices and the use of internal generation partially offset by a decrease in the cost of hedging instruments. The volume of MWhs increased for the six months due to increased reliance on internal generation, as it was more economical to generate than purchase power. The average cost per MWh for fuel for power generation for the six months ended June 30, 2008, as compared to the same period in 2007, decreased due to a decrease in the cost of hedging instruments which were offset by an increase in natural gas prices. In addition, fuel for generation costs decreased as a result of 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.

Gas Purchased for Resale

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %


Gas purchased for resale	$	27,632	$	19,862		39.1	%	$	94,528	$	91,508		3.3	%

Gas purchased for resale
(in thousands of decatherms)		2,565		2,322		10.5	%		9,711		9,795		-0.9	%

Average cost per decatherm	$	10.77	$	8.55		26.0	%	$	9.73	$	9.34		4.2	%

Gas purchased for resale and average cost per decatherm increased for the three and six months ended June 30, 2008 as compared to the same period in 2007. The increase is primarily due to an increase in natural gas prices which were offset by lower costs associated with the settlement of hedging instruments. Volume increased for the three months ended June 30, 2008 compared to the same period in 2007 primarily due to cooler weather. For the six months ended June 30, 2008 volume remained relatively unchanged compared to the same period in the prior year.

Deferral of Energy Costs

	Three Months Ended June 30,								Six Months Ended June 30,
	2008			2007		Change from Prior Year %			2008			2007		Change from Prior Year %

Deferred energy costs - electric - net	$	(11,695	)	$	18,770		-162.3	%	$	(3,188	)	$	32,631		-109.8	%
Deferred energy costs - gas - net		(3,774	)		3,554		-206.2	%		(1,571	)		1,609		-197.6	%
	$	(15,469	)	$	22,324				$	(4,759	)	$	34,240

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

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Deferral of energy costs - electric – net for the three months ended June 30, 2008 and 2007 reflect amortization of deferred energy costs of $8.6 and $11.7 million respectively; and an under-collection of amounts recoverable in rates of $20.3 million in 2008, and an over-collection of $7.1 million in 2007. For the six months ended June 30, 2008 and 2007, amortization of deferred energy costs were $18.6 million and $23.7 million, respectively; with an under-collection of amounts recoverable in rates of $21.8 million in 2008, and over-collection of $8.9 million in 2007.

Deferred energy costs - gas - net for the three months ended June 30, 2008 and 2007 reflect amortization of deferred energy costs of ($0.2) million, and $0.2 million, respectively; and an under-collection of amounts recoverable in rates in 2008 of $3.5 million and an over-collection of $3.4 million in 2007. For the six months ended June 30, 2008 and 2007, amortization of deferred energy costs were ($0.9) million and $0.6 million, respectively; with an under-collection of amounts recoverable in rates of $0.7 million and an over-collection of $1 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change from Prior Year %			2008		2007		Change from Prior Year %

Allowance for other funds
used during construction	$	5,421	$	3,365		61.1	%	$	10,520	$	6,834		53.9	%

Allowance for borrowed funds used during construction	$	4,068	$	2,671		52.3	%	$	7,865	$	5,455		44.2	%
	$	9,489	$	6,036		57.2	%	$	18,385	$	12,289		49.6	%

AFUDC increased for the three and six months ended June 30, 2008 compared to the same period in 2007 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 June 30,									Six Months Ended June 30,
	2008			2007			Change from Prior Year %			2008			2007			Change from Prior Year %

Other operating expense	$	34,765		$	35,994			-3.4	%	$	68,270		$	68,842			-0.8	%
Maintenance expense	$	7,864		$	10,314			-24	%	$	14,336		$	16,595			-13.6	%
Depreciation and amortization	$	22,018		$	20,845			5.6	%	$	43,458		$	41,317			5.2	%
Interest charges on long-term debt	$	18,578		$	16,542			12.3	%	$	37,340		$	32,650			14.4	%
Interest charges-other	$	1,369		$	1,583			-13.5	%	$	2,991		$	3,042			-1.7	%
Interest accrued on deferred energy	$	627		$	(346	)		-281.2	%	$	1,185		$	(1,111	)		-206.7	%
Other income	$	(1,229	)	$	(3,011	)		-59.2	%	$	(8,964	)	$	(4,842	)		85.1	%
Other expense	$	2, 881		$	2, 191			31.5	%	$	4,681		$	4,205			11.3	%

Other operating expense decreased for the three months ended June 30, 2008 compared to the same period in 2007 primarily due to lower costs for claims.

Other operating expense decreased slightly for the six months ended June 30, 2008 compared to the same period in 2007 primarily due to a reduction in bad debt expense and lower costs for claims, partially offset by lower allocations of administrative and general costs to capital projects.

Maintenance expense decreased for the three and six months ended June 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.

Depreciation and amortization expenses increased for the three and six months ended June 30, 2008 compared to the same period in 2007 primarily as a result of increases to plant-in-service.

Interest charges on long-term debt for the three months and six months ended June 30, 2008 increased from 2007 due primarily to the issuance of $325 million Series P General and Refunding Mortgage Notes in June 2007 and higher interest rates for variable rate debt in 2008, offset partially by the redemptions of the $320 million Series A General and Refunding Mortgage Bonds of $221 million and $99 million in June 2007 and June 2008, respectively. See Note 4, 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.

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Interest charges-other for the three months and six months ended June 30, 2008 did not change significantly.

Interest accrued on deferred energy costs decreased for the three months and six months ended June 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 decreased during the three months ended June 30, 2008, when compared to the same period in 2007, due primarily to a refund of expenses in 2007, lower interest income in 2008, and lower gains associated with disposition of property in 2008.

Other income increased during the six months ended June 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.

Other expense increased during the three months and six months ended June 30, 2008, when compared to the same period in 2007, due to adjustments resulting from the decision in SPPC’s GRC. See Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for further information.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the six months ended June 30, 2008 compared to the same period in 2007 due to a decrease in cash from operating and financing activities, partially offset by a decrease in cash used for investing 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 . Cash from financing activities decreased primarily due to a reduction in debt financing in 2008 and an increase in 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 June 30, 2008 (in millions)
Cash and Cash Equivalents	$	21.8
Balance available on Revolving Credit Facility (1)	$	153.2

	$	175.0

1 As of August 4, 2008, SPPC had approximately $93.2 million available under its revolving credit facility.

In addition to cash on hand and the revolving credit facility, SPPC may issue debt up to $1.3 billion on a consolidated basis, subject to certain limitations discussed below.

For the six months ended June 30, 2008, SPR contributed capital to SPPC of approximately $20 million for general corporate purposes. For the six months ended June 30, 2008, SPPC paid dividends to SPR of approximately $63.3 million. On August 4, 2008 SPPC declared an additional dividend to SPR for $15.0 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 requirement, SPPC may use hedging activities. However, 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.

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During the six months ended June 30, 2008, there were no material changes to contractual obligations as set forth in SPPC’s 2007 Form 10-K.

Financing Transactions

Maturity of General and Refunding Mortgage Bonds, Series A

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 will remain the sole holder of the Water Bonds. 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 June 30, 2008, SPPC was in compliance with these covenants.

Ability to Issue Debt

Ability to Issue General and Refunding Mortgage Securities

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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 August 1, 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 actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of SPPC’s auction rate securities of approximately $ 348.3 million as of June 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 issues underlying rating and the Insurer's rating. As of June 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 six 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 set during the second quarter 2008, ranging from a low of 4.32% to a high of 8.66%, and a low of 3.64 % to a high of 10.00% for the six months ended June 30, 2008, with a weighted average interest rate of 5.64% for the six months ended June 30, 2008.

In July 2008, SPPC converted the $40 million of Water 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.

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 CPUC. In addition, the PUCN, California Public Utilities Commission (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.

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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 June 30, 2008, NPC’s and SPPC’s balance sheets included approximately $247.7 million and credit of $29.0 million, respectively, of deferred energy costs of which $239.0 million and a credit of $2.1 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 June 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		$	530,352
Average Interest Rate		-			-			-			-			7.80	%		7.77	%		7.77	%

NPC
Fixed Rate	$	3		$	-		$	-		$	364,000		$	130,000		$	1,786,579		$	2,280,582		$	2,273,162
Average Interest Rate		8.17	%		-			-			8.14	%		6.50	%		6.34	%		6.64	%
Variable Rate	$	-		$	15,000		$	140,000		$	-		$	-		$	192,500		$	347,500		$	347,500
Average Interest Rate		-			5.26	%		3.24	%		-			-			5.98	%		4.85	%

SPPC
Fixed Rate	$	1,062		$	600		$	-		$	-		$	100,000		$	625,000		$	726,662		$	716,647
Average Interest Rate		6.40	%		6.40	%		-			-			6.25	%		6.39	%		6.37	%
Variable Rate	$	-		$	-		$	178,000		$	-		$	-		$	348,250		$	526,250		$	526,250
Average Interest Rate		-			-			3.34	%		-			-			5.64	%		4.86	%

Total Debt	$	1,065		$	15,600		$	318,000		$	364,000		$	293,670		$	3,412,868		$	4,405,203		$	4,393,911

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 $865.4 million as of June 30, 2008, which increased from the $4.9 million balance at December 31, 2007 and the $58.9 million balance at June 30, 2007. Approximately $412.2 million of the increase from December 31, 2007 is primarily the result of increased prices of oil and natural gas during the first two quarters of 2008. The remainder of the increase from December 31, 2007, or $453.2 million, is due to the addition of a 10-year tolling agreement with Dynegy Power Marketing for the entire output of the 570 MW Griffith Energy facility executed during the second quarter of 2008.

ITEM 4 AND ITEM 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

SPR, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of June 30, 2008, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the second 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 quarter ended March 31, 2008, except as discussed below.

Sierra Pacific Resources and Nevada Power Company

Merrill Lynch/Allegheny Lawsuit

In May 2003, SPR and NPC filed suit against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc. and Allegheny Energy Supply Co., LLC (collectively, Allegheny) in the United States District Court, District of Nevada, for compensatory and punitive damages of $850 million for causing the PUCN to disallow the approximate $180 million rate adjustment for NPC in its 2001 deferred energy case (as discussed in Note 3, Regulatory Actions of the Notes to Financial Statements). The PUCN held that NPC acted imprudently when it refused to enter into an electricity supply contract with Merrill Lynch and subsequently paid too much for electricity from another source. SPR and NPC allege that Merrill Lynch and Allegheny’s fraudulent testimony and wrongful conduct caused the PUCN disallowance, among other allegations.

Merrill Lynch filed motions to dismiss in May 2003 and June 2003. Thereafter, the case was stayed pending resolution of NPC’s appeal of the 2001 deferred energy case pending before the Nevada Supreme Court, which was decided in August 2006 and discussed further in Note 3, Regulatory Actions of the Notes to Financial Statements. The Nevada District Court has yet to rule on the motions to dismiss. In October 2006, the District Court approved a stipulation continuing a stay of the proceeding pending final resolution of the PUCN remand proceedings in the 2001 deferred energy case. In May 2007, SPR and NPC filed a motion to amend their complaint to reflect the Nevada Supreme Court’s decision in the appeal and include additional damages (Motion to Amend). In June 2007, Allegheny and Merrill Lynch filed a motion in opposition to SPR and NPC’s Motion to Amend before the Nevada District Court on the ground that the Utilities’ recovery of the $189.9 million in rates under the PUCN Order on remand from the Nevada Supreme Court is all that SPR and NPC are entitled to recover and otherwise for failure to file a timely amended complaint (Motion in Opposition). In July 2007 the Court denied Allegheny and Merrill Lynch’s Motion in Opposition and further set the case for trial in July 2008. In June 2008, Allegheny and Merrill Lynch settled with NPC on this matter for an immaterial amount.

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, 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 June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the Federal Energy Regulatory Commission, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC. Management cannot predict the timing or outcome of a decision in this matter.

The Utilities have negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy (EPME), now known as El Paso Marketing L.P., Calpine Energy Services and Enron, but have been unable to reach agreement in bilateral settlement discussions with other respondents, including Allegheny, Merrill Lynch, American Electric Power and BP.

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Nevada Power Company

Lawsuit Against Natural Gas Providers

In April 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders. In July 2003, SPR and NPC filed a First Amended Complaint. A Second Amended Complaint was filed in June 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric. On December 13, 2005, the District Court dismissed SPR and NPC’s claims. SPR and NPC appealed this decision to the Ninth Circuit Court of Appeals. Subsequently, SPR abandoned its appeal and the matter proceeded only with respect to NPC. In September 2007, the Ninth Circuit reversed the District Court’s order. In November 2007, the Ninth Circuit denied the gas providers and traders’ petition for rehearing. The Ninth Circuit has remanded the case to the District Court for further proceedings. In January 2008, the defendants filled motions to dismiss, to which NPC responded in February 2008. In June 2008, NPC’s claims survived the defendant’s filled motions to dismiss and are now in discovery. Management cannot predict the timing or outcome of a decision on this matter.

Environmental

Nevada Power Company

Reid Gardner Station

Surface and Groundwater Matters

Reid Gardner Station is a coal generating station consisting of four units. NPC owns and operates 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.

Pond construction and lining costs to satisfy the NDEP order expended as of June 30, 2008 is approximately $45 million. Additional expenditures through 2010 are projected to be approximately $2.8 million, for a total expenditure of approximately $47.8 million.

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 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.

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NEICO

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 quarter ended March 31, 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

The 2008 Annual Meeting of the Stockholders of Sierra Pacific Resources was held at 10:00 a.m., Pacific Daylight Time, on Monday April 28, 2008, at the Las Vegas Hilton, 3000 Paradise Road, Las Vegas, Nevada.

Five proposals were presented for stockholder consideration: (1) election of three members of the Board of Directors to serve until the Annual Meeting in 2011, and until their successors are elected and qualified; (2) to consider whether to adopt a shareholder proposal requesting Directors to take the steps necessary to eliminate classification of the terms of the Board of Directors to require that all Directors stand for election annually; (3) to approve the material terms of the performance goals of the Company’s Restated Executive Long-Term Incentive Plan; (4) to approve the amendments to the Company’s Employee Stock Purchase Plan; and (5) to ratify the selection of the Company’s independent registered public accounting firm. Detailed information regarding each of these proposals was included in SPR’s Quarterly Report on Form 10-Q for the Quarter ended March 31, 2008. Set forth below are the final voting results with respect to each proposal.

Three Directors, Joseph B. Anderson, Jr., Glenn C. Christenson, and Philip G. Satre, were elected to serve three year terms expiring at the 2011 Annual Meeting of Stockholders. Directors whose term expires in 2009: Mary Lee Coleman, Theodore J. Day, Jerry E. Herbst and Donald D. Snyder. Directors whose term expires in 2010: Walter M. Higgins (since retired), Brian J. Kennedy, John F. O’Reilly and Michael W. Yackira.

The certified voting results are shown below:

Election of Directors	For	Withheld

Joseph B. Anderson, Jr.	190,071,676	5,074,252
Glenn C. Christenson	191,917,251	3,227,070
Philip G. Satre	171,926,946	23,218,519

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The proposal requesting Directors to take the steps necessary, in the most expeditious manner possible, to adopt annual election of each Director received the votes as set forth below. A majority of the votes entitled to be cast at the Annual Meeting was required to approve the Shareholder proposal; accordingly, the proposal was approved.

For	Against	Abstain

134,446,863	12,688,127	240,678
57.48%	5.42%	0.10%

The proposal requesting to approve the material terms of the performance goals of the Company’s Restated Executive Long-Term Incentive Plan received the votes as set forth below. A majority of the votes cast at the Annual Meeting was required to approve this proposal; accordingly, the proposal was approved.

For	Against	Abstain

185,914,394	8,699,619	531,109
79.49%	3.72%	0.23%

The proposal requesting to approve the amendments to the Company’s Employee Stock Purchase Plan received the votes as set forth below. A majority of the votes cast at the Annual Meeting was required to approve this proposal; accordingly, the proposal was approved.

For	Against	Abstain

144,842,971	2,332,694	200,005
61.93%	1.00%	0.085%

The proposal requesting to ratify the selection of the Company’s independent registered public accounting firm received the votes as set forth below. A majority of the votes cast at the Annual Meeting was required to approve this proposal; accordingly, the proposal was approved.

For	Against	Abstain

192,355,551	2,360,581	421,744
82.24%	1.01%	0.18%

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

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

(10) Nevada Power Company:

10.1 Asset Purchase Agreement dated April 21, 2008, between Reliant Energy Wholesale Generation, LLC,

Reliant Energy Asset Management, LLC and Nevada Power Company.

(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.

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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: August 5, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 5, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)



	Nevada Power Company
	(Registrant)

Date: August 5, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 5, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)



	Sierra Pacific Power Company
	(Registrant)

Date: August 5, 2008	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 5, 2008	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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