form10-q.htm

ITEM 1.	Financial Statements

Sierra Pacific Resources -

	Consolidated Balance Sheets – June 30, 2007 and December 31, 2006…………...……...…………..….........................................	3

	Consolidated Income Statements – Three Months and Six Months Ended June 30, 2007 and 2006...………….................................	4

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006…..…………………....................................	5

Nevada Power Company -

	Consolidated Balance Sheets – June 30, 2007 and December 31, 2006…………...……...…………..….........................................	6

	Consolidated Income Statements – Three Months and Six Months Ended June 30, 2007 and 2006...………….................................	7

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006…..…………………....................................	8

Sierra Pacific Power Company -

	Consolidated Balance Sheets – June 30, 2007 and December 31, 2006…………...……...…………..….........................................	9

	Consolidated Income Statements – Three Months and Six Months Ended June 30, 2007 and 2006...…………..................................	10

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006…..………………….....................................	11

Condensed Notes to Consolidated Financial Statements……………………………………………………………………................................		12

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations…………………........................................	26
	Sierra Pacific Resources ………………………………………………….……………………………...................................	30
	Nevada Power Company …………………………………………………….…………………………….............................	34
	Sierra Pacific Power Company ……………………………………………………………………………..............................	40

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk…………………………………………………....................................	50

ITEM 4.	Controls and Procedures…………………………………………………………………………………………............................	50

	PART II - OTHER INFORMATION
ITEM 1.	Legal Proceedings…………………………………………………………………………...…………….......................................	51

ITEM 1A.	Risk Factors……………………………………………………………………………………………………..............................	52

ITEM 4.	Submission of Matters to a Vote of Security Holders…………………………………………………………..................................	54

ITEM 5.	Other Information…………………………………………………………………………………………......................................	55

ITEM 6.	Exhibits …………………………………………………….…………………………………………………................................	56

Signature Page and Certifications…..…………………………………………………………………………...…………..........................................		57

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	June 30,		December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	8,221,210	$	7,954,337
Less accumulated provision for depreciation		2,427,155		2,333,357
		5,794,055		5,620,980
Construction work-in-progress		762,727		466,018
		6,556,782		6,086,998

Investments and other property, net		33,112		34,325

Current Assets:
Cash and cash equivalents		146,916		115,709
Accounts receivable less allowance for uncollectible accounts: 2007-$38,198; 2006-$39,566		490,767		415,082
Deferred energy costs - electric (Note 1)		232,571		168,260
Materials, supplies and fuel, at average cost		108,217		103,757
Risk management assets (Note 5)		36,774		27,305
Deferred income taxes		74,495		55,546
Deposits and prepayments for energy		7,391		15,968
Other		35,331		31,580
		1,132,462		933,207
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		209,630		382,286
Regulatory tax asset		261,781		263,170
Regulatory asset for pension plans		212,723		223,218
Other regulatory assets		720,567		668,624
Risk management assets (Note 5)		13,895		7,586
Risk management regulatory assets - net (Note 5)		64,012		122,911
Unamortized debt issuance costs		69,214		67,106
Other		73,754		42,645
		1,625,576		1,777,546
TOTAL ASSETS	$	9,347,932	$	8,832,076

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity	$	2,673,234	$	2,622,297
Long-term debt		4,291,833		4,001,542
		6,965,067		6,623,839
Current Liabilities:
Current maturities of long-term debt		109,092		8,348
Accounts payable		341,150		282,463
Accrued interest		48,157		56,426
Accrued salaries and benefits		26,139		33,146
Current income taxes payable		-		5,914
Risk management liabilities (Note 5)		76,182		123,065
Accrued taxes		7,499		6,290
Other current liabilities		66,333		60,422
		674,552		576,074
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes		825,369		791,428
Deferred investment tax credit		33,498		35,218
Regulatory tax liability		32,535		34,075
Customer advances for construction		97,149		91,895
Accrued retirement benefits		231,908		226,420
Risk management liabilities (Note 5)		9,561		10,746
Regulatory liabilities		311,003		301,903
Other		167,290		140,478
		1,708,313		1,632,163
TOTAL CAPITALIZATION AND LIABILITIES	$	9,347,932	$	8,832,076

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

OPERATING REVENUES:
Electric	$	820,464		$	787,891		$	1,491,508		$	1,407,938
Gas		31,378			33,297			116,498			120,022
Other		52			731			319			1,015
		851,894			821,919			1,608,325			1,528,975
OPERATING EXPENSES:
Operation:
Purchased power		262,025			256,701			440,929			510,445
Fuel for power generation		192,058			214,168			420,212			357,277
Gas purchased for resale		19,862			24,352			91,508			91,748
Deferral of energy costs - electric - net		86,501			52,949			127,294			57,021
Deferral of energy costs - gas - net		3,554			1,353			1,609			6,084
Other		92,268			83,081			177,015			173,357
Maintenance		30,633			23,426			54,378			45,356
Depreciation and amortization		59,678			56,622			115,911			114,083
Taxes:
Income taxes / (benefits)		7,244			5,310			6,489			(1,594	)
Other than income		11,640			13,274			24,619			24,938
		765,463			731,236			1,459,964			1,378,715
OPERATING INCOME		86,431			90,683			148,361			150,260

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,612			4,174			13,179			10,306
Interest accrued on deferred energy		3,773			7,638			8,387			16,354
Carrying charge for Lenzie		5,998			9,135			16,080			13,166
Reinstated interest on deferred energy (Note 3)		-			-			11,076			-
Other income		6,382			9,334			13,688			18,597
Other expense		(8,150	)		(4,716	)		(13,066	)		(9,434	)
Income taxes		(4,675	)		(8,758	)		(16,058	)		(16,943	)
		9,940			16,807			33,286			32,046
Total Income Before Interest Charges		96,371			107,490			181,647			182,306

INTEREST CHARGES:
Long-term debt		68,546			77,279			134,995			150,662
Other		7,445			5,016			15,999			10,234
Allowance for borrowed funds used during construction		(5,374	)		(4,007	)		(10,708	)		(10,009	)
		70,617			78,288			140,286			150,887

Preferred stock dividend requirements of subsidiary and premium on redemption		-			1,366			-			2,341
NET INCOME APPLICABLE TO COMMON STOCK	$	25,754		$	27,836		$	41,361		$	29,078

Amount per share basic and diluted - (Note 7)
Net Income applicable to common stock	$	0.12		$	0.14		$	0.19		$	0.14

Weighted-Average Shares of Common Stock Outstanding - basic		221,412,345			200,897,101			221,329,347			200,882,857
Weighted-Average Shares of Common Stock Outstanding - diluted		221,821,195			201,292,738			221,738,312			201,279,301

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income Applicable to Common Stock	$	41,361		$	29,078
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		115,911			114,083
Deferred taxes and deferred investment tax credit		31,661			6,510
AFUDC		(13,179	)		(20,315	)
Amortization of deferred energy costs - electric		88,482			75,025
Amortization of deferred energy costs - gas		638			4,136
Deferral of energy costs - electric		30,941			(34,151	)
Deferral of energy costs - gas		(638	)		1,744
Deferral of energy costs - terminated suppliers		-			2,309
Carrying charge on Lenzie plant		(16,080	)		(13,166	)
Reinstated interest on deferred energy		(11,076	)		-
Other, net		7,805			(3,494	)
Changes in certain assets and liabilities:
Accounts receivable		(75,685	)		(79,082	)
Materials, supplies and fuel		(4,460	)		(10,307	)
Other current assets		4,825			18,961
Accounts payable		53,326			(4,022	)
Payment to terminating supplier		-			(65,368	)
Proceeds from claim on terminating supplier		-			41,365
Other current liabilities		(8,155	)		12,358
Risk Management assets and liabilities		(4,946	)		(15,948	)
Other assets		(14,505	)		5,804
Other liabilities		(12,396	)		1,200
Net Cash from Operating Activities		213,830			66,720

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(598,229	)		(587,156	)
AFUDC and other charges to utility plant		13,179			20,315
Customer advances for construction		5,254			16,190
Contributions in aid of construction		30,312			21,854
Investments in subsidiaries and other property - net		1,381			11,127
Net Cash used by Investing Activities		(548,103	)		(517,670	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			3,612
Proceeds from issuance of long-term debt		1,029,014			2,043,333
Retirement of long-term debt		(672,630	)		(1,522,793	)
Redemption of preferred stock		-			(51,366	)
Proceeds from exercise of stock options		9,096			1,263
Dividends paid		-			(1,944	)
Net Cash from Financing Activities		365,480			472,105

Net Increase in Cash and Cash Equivalents		31,207			21,155
Beginning Balance in Cash and Cash Equivalents		115,709			172,735
Ending Balance in Cash and Cash Equivalents	$	146,916		$	193,890

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	146,941		$	157,870
Income taxes	$	6,824		$	12

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

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	June 30,		December 31,
ASSETS	2007		2006
Utility Plant at Original Cost:
Plant in service	$	5,412,308	$	5,187,665
Less accumulated provision for depreciation		1,339,355		1,276,192
		4,072,953		3,911,473
Construction work-in-progress		368,900		238,518
		4,441,853		4,149,991

Investments and other property, net		20,979		22,176

Current Assets:
Cash and cash equivalents		28,809		36,633
Accounts receivable less allowance for uncollectible accounts: 2007-$31,623; 2006-$32,834		357,687		244,623
Deferred energy costs - electric (Note 1)		202,570		129,304
Materials, supplies and fuel, at average cost		63,331		60,754
Risk management assets (Note 5)		25,677		16,378
Deferred income taxes		46,343		72,294
Deposits and prepayments for energy		6,963		7,056
Other		25,286		19,901
		756,666		586,943
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		209,630		359,589
Regulatory tax asset		154,496		153,471
Regulatory asset for pension plans		110,330		113,646
Other regulatory assets (Note 1)		489,503		440,369
Risk management assets		9,497		5,379
Risk management regulatory assets - net (Note 5)		47,086		83,886
Unamortized debt issuance costs		38,553		38,856
Other		53,916		33,209
		1,113,011		1,228,405
TOTAL ASSETS	$	6,332,509	$	5,987,515

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity	$	2,200,590	$	2,172,198
Long-term debt		2,655,630		2,380,139
		4,856,220		4,552,337
Current Liabilities:
Current maturities of long-term debt		7,449		5,948
Accounts payable		205,806		148,003
Accounts payable, affiliated companies		35,776		20,656
Accrued interest		30,638		37,010
Dividends declared		-		13,472
Accrued salaries and benefits		12,102		14,989
Current income taxes payable		-		3,981
Intercompany Income taxes payable		31,865		884
Risk management liabilities (Note 5)		54,867		84,674
Accrued taxes		4,039		2,671
Other current liabilities		50,110		48,298
		432,652		380,586
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		552,402		599,747
Deferred investment tax credit		14,424		15,213
Regulatory tax liability		12,788		13,451
Customer advances for construction		63,353		60,040
Accrued retirement benefits		97,457		90,474
Risk management liabilities (Note 5)		6,349		7,061
Regulatory liabilities		178,965		171,298
Other		117,899		97,308
		1,043,637		1,054,592

TOTAL CAPITALIZATION AND LIABILITIES	$	6,332,509	$	5,987,515

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
OPERATING REVENUES:
Electric	$	575,108		$	543,869		$	993,273		$	925,144

OPERATING EXPENSES:
Operation:
Purchased power		175,716			187,093			271,310			348,689
Fuel for power generation		140,773			151,694			304,858			241,516
Deferral of energy costs - net		67,731			30,621			94,663			33,788
Other		55,162			47,705			106,001			101,838
Maintenance		20,319			14,431			37,783			28,588
Depreciation and amortization		38,833			34,884			74,594			69,121
Taxes:
Income taxes / (benefits)		8,654			7,859			442			(236	)
Other than income		6,692			7,563			14,426			14,158
		513,880			481,850			904,077			837,462
OPERATING INCOME		61,228			62,019			89,196			87,682

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,247			2,725			6,345			8,154
Interest accrued on deferred energy		3,427			6,126			7,276			12,909
Carrying charge for Lenzie		5,998			9,135			16,080			13,166
Reinstated interest on deferred energy (Note 3)		-			-			11,076			-
Other income		2,909			4,385			8,030			8,751
Other expense		(5,384	)		(2,338	)		(7,426	)		(4,303	)
Income taxes		(3,553	)		(6,641	)		(14,131	)		(13,050	)
		6,644			13,392			27,250			25,627
Total Income Before Interest Charges		67,872			75,411			116,446			113,309

INTEREST CHARGES:
Long-term debt		41,368			46,191			81,074			88,930
Other		5,603			3,464			12,439			7,291
Allowance for borrowed funds used during construction		(2,703	)		(2,700	)		(5,253	)		(8,072	)
		44,268			46,955			88,260			88,149

NET INCOME	$	23,604		$	28,456		$	28,186		$	25,160


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

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	28,186		$	25,160
Adjustments to reconcile net income to net cash from or (used by)
operating activities:
Depreciation and amortization		74,594			69,121
Deferred taxes and deferred investment tax credit		9,826			3,983
AFUDC		(6,345	)		(16,226	)
Amortization of deferred energy costs		64,747			52,399
Deferral of energy costs		23,023			(31,516	)
Deferral of energy costs - terminated suppliers		-			1,607
Carrying charge on Lenzie plant		(16,080	)		(13,166	)
Reinstated interest on deferred energy		(11,076	)		-
Other, net		(3,394	)		(12,650	)
Changes in certain assets and liabilities:
Accounts receivable		(113,064	)		(119,536	)
Materials, supplies and fuel		(2,576	)		(8,573	)
Other current assets		(5,292	)		(2,718	)
Accounts payable		65,001			9,011
Payment to terminating supplier		-			(37,410	)
Proceeds from claim on terminating supplier		-			26,391
Other current liabilities		(6,077	)		10,858
Risk Management assets and liabilities		(7,135	)		(9,111	)
Other assets		(10,829	)		4,700
Other liabilities		5,288			(3,102	)
Net Cash from (used by) Operating Activities		88,797			(50,778	)

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(369,586	)		(439,465	)
AFUDC and other charges to utility plant		6,345			16,226
Customer advances for construction		3,313			11,598
Contributions in aid of construction		20,289			15,402
Investments in subsidiaries and other property - net		1,366			5,865
Net Cash used by Investing Activities		(338,273	)		(390,374	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		569,586			1,549,833
Retirement of long-term debt		(314,462	)		(1,120,448	)
Dividends paid		(13,472	)		(31,968	)
Net Cash from Financing Activities		241,652			397,417

Net Decrease in Cash and Cash Equivalents		(7,824	)		(43,735	)
Beginning Balance in Cash and Cash Equivalents		36,633			98,681
Ending Balance in Cash and Cash Equivalents	$	28,809		$	54,946

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	90,847		$	92,705
Income taxes	$	6,760		$	3,159

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	June 30,		December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,808,902	$	2,766,672
Less accumulated provision for depreciation		1,087,800		1,057,165
		1,721,102		1,709,507
Construction work-in-progress		393,827		227,500
		2,114,929		1,937,007

Investments and other property, net		597		609

Current Assets:
Cash and cash equivalents		93,941		53,260
Accounts receivable less allowance for uncollectible accounts:
2007-$6,575; 2006-$6,732		132,894		170,106
Deferred energy costs - electric (Note 1)		30,001		38,956
Materials, supplies and fuel, at average cost		44,874		42,990
Risk management assets (Note 5)		11,097		10,927
Deposits and prepayments for energy		428		8,912
Other		9,505		11,184
		322,740		336,335
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		-		22,697
Regulatory tax asset		107,285		109,699
Regulatory asset for pension plans		99,649		106,666
Other regulatory assets		231,064		228,255
Risk management assets (Note 5)		4,398		2,207
Risk management regulatory assets - net (Note 5)		16,926		39,025
Unamortized debt issuance costs		21,016		17,981
Other		16,957		7,356
		497,295		533,886
TOTAL ASSETS	$	2,935,561	$	2,807,837

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	916,994	$	884,737
Long-term debt		1,085,764		1,070,858
		2,002,758		1,955,595
Current Liabilities:
Current maturities of long-term debt		101,643		2,400
Accounts payable		99,095		89,743
Accounts payable, affiliated companies		15,672		11,769
Accrued interest		5,303		7,200
Dividends declared		-		6,736
Accrued salaries and benefits		11,958		15,209
Intercompany income taxes payable		10,982		9,055
Deferred income taxes		5,779		8,881
Risk management liabilities (Note 5)		21,315		38,391
Accrued taxes		3,339		3,407
Other current liabilities		16,222		12,125
		291,308		204,916
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		266,858		278,515
Deferred investment tax credit		19,074		20,005
Regulatory tax liability		19,747		20,624
Customer advances for construction		33,796		31,855
Accrued retirement benefits		121,901		124,254
Risk management liabilities (Note 5)		3,212		3,685
Regulatory liabilities		132,038		130,605
Other		44,869		37,783
		641,495		647,326
TOTAL CAPITALIZATION AND LIABILITIES	$	2,935,561	$	2,807,837

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
OPERATING REVENUES:
Electric	$	245,356		$	244,022		$	498,235		$	482,794
Gas		31,378			33,297			116,498			120,022
		276,734			277,319			614,733			602,816
OPERATING EXPENSES:
Operation:
Purchased power		86,309			69,608			169,619			161,756
Fuel for power generation		51,285			62,474			115,354			115,761
Gas purchased for resale		19,862			24,352			91,508			91,748
Deferral of energy costs - electric - net		18,770			22,328			32,631			23,233
Deferral of energy costs - gas - net		3,554			1,353			1,609			6,084
Other		35,994			33,119			68,842			67,294
Maintenance		10,314			8,995			16,595			16,768
Depreciation and amortization		20,845			21,738			41,317			44,962
Taxes:
Income taxes		2,686			2,878			11,046			9,727
Other than income		4,902			5,671			10,088			10,689
		254,521			252,516			558,609			548,022
OPERATING INCOME		22,213			24,803			56,124			54,794

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,365			1,449			6,834			2,152
Interest accrued on deferred energy		346			1,512			1,111			3,445
Other income		3,011			2,662			4,842			4,810
Other expense		(2,191	)		(2,144	)		(4,205	)		(4,668	)
Income taxes		(1,282	)		(1,199	)		(2,493	)		(2,022	)
		3,249			2,280			6,089			3,717
Total Income Before Interest Charges		25,462			27,083			62,213			58,511

INTEREST CHARGES:
Long-term debt		16,542			18,134			32,650			35,824
Other		1,583			1,257			3,042			2,353
Allowance for borrowed funds used during construction		(2,671	)		(1,307	)		(5,455	)		(1,937	)
		15,454			18,084			30,237			36,240

NET INCOME		10,008			8,999			31,976			22,271

Dividend requirements of preferred stock		-			1,366			-			2,341
EARNINGS APPLICABLE TO COMMON STOCK	$	10,008		$	7,633		$	31,976		$	19,930

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	31,976		$	22,271
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		41,317			44,962
Deferred taxes and deferred investment tax credit		(7,652	)		(37,847	)
AFUDC		(6,834	)		(4,089	)
Amortization of deferred energy costs - electric		23,735			22,626
Amortization of deferred energy costs - gas		638			4,136
Deferral of energy costs - electric		7,918			(2,634	)
Deferral of energy costs - gas		(638	)		1,744
Deferral of energy costs - terminated suppliers		-			702
Other, net		11,221			6,230
Changes in certain assets and liabilities:
Accounts receivable		37,212			71,200
Materials, supplies and fuel		(1,884	)		(1,722	)
Other current assets		10,161			21,399
Accounts payable		15,814			5,746
Payment to terminating supplier		-			(27,958	)
Proceeds from claim on terminating supplier		-			14,974
Other current liabilities		(1,119	)		2,348
Risk Management assets and liabilities		2,189			(6,837	)
Other assets		(3,677	)		1,103
Other liabilities		(4,493	)		8,220
Net Cash from Operating Activities		155,884			146,574

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(228,643	)		(147,691	)
AFUDC and other charges to utility plant		6,834			4,089
Customer advances for construction		1,941			4,592
Contributions in aid of construction		10,023			6,452
Investments in subsidiaries and other property - net		12			(29	)
Net Cash used by Investing Activities		(209,833	)		(132,587	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			3,612
Proceeds from issuance of long-term debt		459,428			493,500
Retirement of long-term debt		(358,062	)		(402,181	)
Redemption of preferred stock		-			(51,366	)
Dividends paid		(6,736	)		(17,926	)
Net Cash from Financing Activities		94,630			25,639

Net Increase in Cash and Cash Equivalents		40,681			39,626
Beginning Balance in Cash and Cash Equivalents		53,260			38,153
Ending Balance in Cash and Cash Equivalents	$	93,941		$	77,779

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	34,823		$	38,541
Income taxes	$	64		$	12

Non-cash Activities:
Transfer of Regulatory Asset	$	-		$	18,888
The accompanying notes are an integral part of the financial statements (unaudited).

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements of Sierra Pacific Resources (SPR) include the accounts of SPR and its wholly-owned subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC) (collectively, the "Utilities"), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications (SPC) and Sierra Water Development Company (SWDC). The consolidated financial statements of NPC include the accounts of NPC and its wholly-owned subsidiary, Nevada Electric Investment Company (NEICO). The consolidated financial statements of SPPC include the accounts of SPPC and its wholly-owned subsidiaries, GPSF-B, Piñon Pine Corporation (PPC), Piñon Pine Investment Company, Piñon Pine Company, L.L.C. and Sierra Pacific Funding L.L.C. All significant intercompany transactions and balances have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

In the opinion of the management of SPR, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain all adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2006 (the “2006 Form 10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the six months ended June 30, 2007, are not necessarily indicative of the results to be expected for the full year.

Carrying Charge on the Lenzie Generating Station

In 2004, the Public Utilities Commission of Nevada (PUCN) granted NPC’s request to designate the Chuck Lenzie Generating Station (Lenzie) as a critical facility and allowed a 2% enhanced Return on Equity (ROE) to be applied to the Lenzie construction costs expended after acquisition. The order allowed for an additional 1% enhanced ROE if the two Lenzie generating units were brought on line early. In addition, the PUCN granted NPC’s request to begin accumulating a carrying charge as a regulatory asset including the 3% enhanced ROE (collectively referred to as “carrying charges”), until the plant is included in rates.

Units 1 and 2 were declared commercially operable in January 2006 and April 2006, respectively, qualifying for the incentive ROE treatment. As of June 30, 2007, NPC has accumulated approximately $57.6 million in carrying charges; however, $8.1 million of this amount has not been recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through regulated rates. For financial reporting purposes, through June 30, 2007, NPC has recognized a cumulative of $49.5 million in income, and recorded a corresponding regulatory asset, which represents only the carrying charge component associated with incurred debt costs. For the three and six month periods ending June 30, 2007, NPC recognized $6.0 million and $16.1 million in income, respectively.

In May 2007, the PUCN issued its order on NPC’s 2006 General Rate Case (GRC) authorizing recovery of the carrying charges, effective as of June 1, 2007. NPC was authorized to recover over a 35 year period $30.3 million of the carrying charges calculated through the certification period ending October 31, 2006. Beginning June 1, 2007, NPC began recognizing its full return on Lenzie through rates rather than as a separate carrying charge component. NPC will seek recovery of the remaining $27.3 million of carrying charges calculated subsequent to the certification period in its next GRC.

Deferral of Energy Costs

NPC and SPPC follow deferred energy accounting. See the 2006 Form 10-K, Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements for additional information regarding the implementation of deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of June 30, 2007 (dollars in thousands):

	June 30, 2007
	NPC			SPPC			SPPC			SPR
Description	Electric			Electric			Gas			Total
Unamortized balances approved for collection in current rates
Electric – NPC Period 1 (Reinstatement of deferred Energy)(1)	$	188,282		$	-		$	-		$	188,282
Electric – SPPC Period 3 (effective 6/05, 25 months)		-			(2,289	)		-			(2,289	)
Electric – NPC Period 5 (effective 8/06, 2 years)		114,883			-			-			114,883
Electric – SPPC Period 5 (effective 7/06, 2 years)		-			15,055			-			15,055
Electric – NPC Period 6 (effective 6/07, 14 months)		53,152			-			-			53,152
Electric – SPPC Period 6 (effective 7/07, 1 year)		-			16,130			-			16,130
Nat Gas – P6, LPG – P5 (effective 12/06, 1 year)		-			-			287			287
Western Energy Crisis Rate Case (1)		77,794			-			-			77,794
Balances pending PUCN approval		-			-			860			860
Cumulative CPUC balance		-			6,585			-			6,585
Balances accrued since end of periods submitted for PUCN approval		(21,911	)		(21,746	)		(2,966	)		(46,623	)
Western Energy Crisis Rate Case (2)		-			16,266			-			16,266

Total	$	412,200		$	30,001		$	(1,819	)⁽³⁾	$	440,382

Current Assets
Deferred energy costs - electric	$	202,570		$	30,001		$	-		$	232,571
Deferred energy costs - gas		-			-			-			-
Deferred Assets
Deferred energy costs - electric		209,630			-			-			209,630
Deferred energy costs - gas		-			-			-			-
Other current liabilities		-			-			(1,819	)		(1,819	)
Total	$	412,200		$	30,001		$	(1,819	)	$	440,382

(1)	Reference discussion in Note 3, Regulatory Actions, of the Condensed Notes to Consolidated Financial Statements.

(2)	SPPC’s Western Energy Crisis Rate Case is discussed in Note 3, Regulatory Actions, of the Condensed Notes to the Consolidated Financial Statements.

(3)	Amount included within other current liabilities.

Recent Pronouncements

FIN 48

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”) to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006, and, therefore, has been adopted as of January 1, 2007 by SPR and the Utilities. As a result of the implementation of FIN 48, SPR and the Utilities recorded an increase of approximately $487 thousand to the January 1, 2007 balance of retained earnings as a cumulative effect adjustment.

SPR and the Utilities file a consolidated U.S. federal income tax return. The U.S. federal jurisdiction is the only “major” tax jurisdiction for the Company. In connection with the previous examination cycles, the statute of limitations for tax years 1997 through 2003 was extended to December 31, 2008. The audits of tax years 1997 through 2004 have been completed, but are pending Joint Committee on Taxation notification. The statute of limitations for tax years 2004 and 2005 expire on September 15, 2008 and 2009, respectively. All earlier years are closed by statute.

SPR and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively. The total amount of unrecognized tax benefits as of June 30, 2007 is $16.2 million, of which $2.2 million would affect the effective tax rate if recognized. The amount of unrecognized tax benefits primarily decreased from the first quarter by a total of $10.7 million. This decrease relates to two separate uncertain tax positions: (1) the amount decreased by $14.5 million as a result of an uncertain tax position taken by SPR on a prior year tax return related to a financial instrument; and (2) the amount increased by $3.8 million related to a new uncertain tax position identified during the current quarter. No interest or penalties have been accrued as of June 30, 2007. No significant increases or decreases to unrecognized tax benefits are expected within the next 12 months.

SFAS 157

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (SFAS 157). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for SPR and the Utilities beginning January 2008. SPR and the Utilities are currently evaluating the impact of the adoption of SFAS 157 on their consolidated financial statements.

SFAS 159

In February 2007, the FASB issued FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), which permits entities to choose to measure many financial instruments and certain other items at fair value. The objective of the statement is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of SFAS 159 are effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. SPR and the Utilities are currently evaluating the potential impact of the adoption of SFAS 159.

FIN 39-1

In April 2007, the FASB issued FASB Staff Position on Interpretation 39, "Amendment of FASB Interpretation No. 39," ("FIN 39-1"). Under FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for a cash collateral paid or a cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FIN 39-1 is effective for fiscal years beginning after November 15, 2007. SPR and the Utilities are currently evaluating the impact of the adoption of FIN 39-1 on their consolidated financial statements.

NOTE 2. SEGMENT INFORMATION

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

Operational information of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which, the primary financial measure is business segment operating income. The accounting policies of the business segments are the same as those described in the 2006 Form 10-K, Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements. Inter-segment revenues are insignificant (dollars in thousands).

Three Months Ended	NPC		SPPC		Total
June 30, 2007	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	575,108	$	245,356	$	820,464	$	31,378	$	52	$	851,894
Operating Income	$	61,228	$	21,247	$	82,475	$	966	$	2,990	$	86,431

Three Months Ended	NPC		SPPC		Total
June 30, 2006	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	543,869	$	244,022	$	787,891	$	33,297	$	731	$	821,919
Operating Income	$	62,019	$	24,032	$	86,051	$	771	$	3,861	$	90,683


Six Months Ended	NPC		SPPC		Total
June 30, 2007	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	993,273	$	498,235	$	1,491,508	$	116,498	$	319	$	1,608,325
Operating Income	$	89,196	$	49,518	$	138,714	$	6,606	$	3,041	$	148,361

Six Months Ended	NPC		SPPC		Total
June 30, 2006	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	925,144	$	482,794	$	1,407,938	$	120,022	$	1,015	$	1,528,975
Operating Income	$	87,682	$	48,810	$	136,492	$	5,984	$	7,784	$	150,260

NOTE 3. REGULATORY ACTIONS

Pending Rate Cases

Nevada Power Company

NPC Fourth Amendment to 2006 Integrated Resource Plan (IRP)

In July 2007, NPC filed its fourth amendment to its 2006 IRP requesting to expend $13.2 million on various transmission projects. In addition, NPC requested approval of various renewable energy purchase power agreements, totaling 139.5 megawatts (MWs), to be built over the next two to four years.

Sierra Pacific Power Company

SPPC 2007 Nevada Integrated Resource Plan

In June 2007, SPPC filed its 2007 triennial IRP with the PUCN. The following are the key elements of the filing:

·	requested approval for approximately $176 million in transmission projects;

requested approval of four new demand side programs and to increase spending on seven existing demand side programs (total expenditures of $28.4 million). The demand side programs are intended to help customers use electricity more efficiently and also contribute to SPPC’s Renewable Portfolio requirements; and

requested approval to expend $16.5 million, an increase of $8.2 million, on the replacement of the diesel units in Kings Beach, California. The increase in costs is the result of higher material costs and the costs to meet the environmental requirements of the Tahoe Regional Planning Administration.

SPPC 2007 Nevada Natural Gas and Propane Deferred Energy Rate Case and Base Tariff Energy Rate (BTER) Update

In May 2007, SPPC filed an application to create a new Deferred Energy Accounting Adjustment (DEAA) rate and to update the going forward BTER. SPPC requests to increase rates by $13.4 million, while recovering $900 thousand of deferred gas costs. This application requests an overall rate increase of 7.05%. Hearings on these matters are scheduled for the end of October 2007.

SPPC 2006 Nevada Western Energy Crisis Rate Case

In December 2006, SPPC filed an application to recover $22.6 million in deferred legal and settlement costs incurred to resolve claims arising from the Western Energy Crisis. This application requested an overall rate increase of 0.53% and to begin amortizing the costs over a four-year period beginning July 1, 2007.

In February 2007, SPPC entered into a stipulation pursuant to which SPPC replaced its request to implement rates on July 1, 2007 with a request to recover approximately $16.3 and $6.3 million, respectively, in deferred settlement and legal costs. SPPC further requested authority to recover carrying charges on the regulatory asset. Hearings on this matter are scheduled for early October 2007.

SPPC Nevada 2003 General Rate Case

As described in more detail in the 2006 Form 10-K, Note 13 Commitments and Contingencies of the Notes to Financial Statements, in connection with SPPC’s 2003 GRC, the PUCN disallowed $43 million of unreimbursed costs associated with the Pinon Pine Coal Gasification Demonstration Project. Through the legal process, the case was ultimately remanded back to the PUCN for further review of whether the costs were justly and reasonably incurred.

A pre-hearing conference on this matter was held in June 2007, during which the parties were directed to file briefs on the scope of the issues they believe are before the PUCN. A second pre-hearing conference is scheduled for August 2007 in which the PUCN will determine the scope of the proceedings and set a procedural schedule. Hearings are expected to be held in the fourth quarter of 2007.

Approved Rate Cases

Nevada Power Company

NPC 2006 General Rate Case

In November 2006, NPC filed its statutorily required electric GRC and further updated the filing in February 2007. The filing requested an ROE and rate of return (ROR) of 11.4% and 9.39% and an increase to general revenues of $156.4 million.

The PUCN issued its order in May 2007, with rates effective as of June 1, 2007. The PUCN order resulted in the following significant items:

·	increase in general rates of $120.1 million, a 5.66% increase;

·	ROE and ROR of 10.7% and 9.06%, respectively;

·	authorized 100% recovery of unamortized 1999 NPC / SPPC merger costs;

·	authorized incentive rate making for Lenzie;

·	authorized recovery of accumulated cost and savings, including the net book value of Mohave over an eight year period, see Note 6, Commitments and Contingencies for further discussion of Mohave.

NPC 2007 Deferred Energy Rate Case and BTER Update

In January 2007, NPC filed an application to create a new DEAA rate and to update the going forward BTER. NPC requested to decrease rates by $33.2 million, while recovering $75 million of deferred fuel and purchased power costs.

In March 2007, NPC filed an update to its going forward BTER which lowered the overall decrease in rates from $33.2 million to $5.9 million, resulting in less than a 1% decrease. NPC requested the amortization to begin June 1, 2007 and to continue for a 14-month period.

In June 2007, the PUCN approved a stipulation between the parties that resolved all the issues in this case with no material impact to the requested rate change with rates effective June 1, 2007.

Material Amendments to NPC’s 2006 Integrated Resource Plan

In January 2007, NPC filed an amendment to its 2006 IRP requesting approval to expend $60 million to install new ultra-low emission burners on the four combustion turbines serving the combined cycle units at the Clark Generating Station.

In May 2007, the PUCN approved a stipulation pursuant to which NPC was authorized to expend $60 million to install the new ultra-low emission burners.

NPC 2007 Western Energy Crisis Rate Case

In January 2007, NPC filed an application to recover $83.6 million in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the Western Energy Crisis. This application requested to begin amortizing the costs over a four-year period beginning June 1, 2007.

In March 2007, the PUCN approved a negotiated settlement where NPC is authorized to recover the $83.6 million plus carrying charges over a three-year period beginning June 1, 2007, which differed from the four-year period requested in the application.

NPC 2001 Deferred Energy Case

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

In March 2002, the PUCN issued its Order on the application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The Order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. NPC and the Bureau of Consumer Protection (BCP) both sought individual review of the PUCN Order in the First District Court of Nevada (the District Court). The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.

In July 2006, the Supreme Court of Nevada issued a ruling reversing $178.8 million of the PUCN’s disallowance which was part of the NPC’s 2001 Deferred Energy Case. The decision directed the District Court to remand the matter back to the PUCN to determine the appropriate rate schedule.

In March 2007, the PUCN approved a stipulation that authorizes NPC to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. The $189.9 million represents Nevada’s jurisdictional portion of the $178.8 million disallowance plus carrying charges of $11.1 million from the date the costs were incurred to the date of disallowance by the PUCN.

Sierra Pacific Power Company

SPPC 2006 Nevada Electric Deferred Energy Rate Case and BTER Update

In December 2006, SPPC filed an application to create a new electric DEAA rate and to update the electric BTER. SPPC requested to decrease rates by $7.9 million, a decrease of .86%, while recovering $18.7 million of deferred fuel and purchased power costs. SPPC sought recovery using a symmetrical two-year amortization period beginning July 1, 2007.

In June 2007, the PUCN approved a stipulation between the parties that resolved all the issues in this case with no material impact to the requested rate change with rates effective July 1, 2007.

NOTE 4. LONG-TERM DEBT

As of June 30, 2007, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the balance of 2007, for the next four years and thereafter are shown below (in thousands):

	NPC			SPPC		SPR Holding Co. and Other Subs.		SPR Consolidated
2007	$	2,514		$	1,053	$	-	$	3,567
2008		7,038			101,643		-		108,681
2009		22,131			600		-		22,731
2010		132,903			-		-		132,903
2011		369,824			-		-		369,824
		534,410			103,296		-		637,706
Thereafter		2,141,738			1,073,250		549,209		3,764,197
		2,676,148			1,176,546		549,209		4,401,903
Unamortized premium (discount) amount		(13,069	)		10,861		1,230		(978	)
Total	$	2,663,079		$	1,187,407	$	550,439	$	4,400,925

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

6.75% General and Refunding Mortgage Notes, Series R

On June 28, 2007, NPC issued and sold $350 million of its 6.75% General and Refunding Mortgage Notes, Series R, due July 1, 2037. The Series R Notes were issued pursuant to a registration statement previously filed with the Securities and Exchange Commission. The net proceeds from the issuance were used to fund the purchase of the tendered Series G Notes (discussed below), repay amounts outstanding under NPC’s revolving credit facility and for general corporate purposes.

Tender Offer for General and Refunding Mortgage Notes, Series G

On June 28, 2007, NPC settled its cash tender offer, which commenced on June 15, 2007 and expired on June 22, 2007, for its 9.00% General and Refunding Mortgage Notes, Series G, due 2013. Those holders who tendered their notes by the expiration date were entitled to receive a purchase price of $1,079.75 per $1,000 principal amount of Series G Notes. Approximately $210.3 million of the $227.5 million Series G Notes outstanding were validly tendered and accepted by NPC.

Sierra Pacific Power Company

6.75% General and Refunding Mortgage Notes, Series P

On June 28, 2007, SPPC issued and sold $325 million of its 6.75% General and Refunding Mortgage Notes, Series P, due July 1, 2037. The Series P Notes were issued pursuant to a registration statement previously filed with the Securities and Exchange Commission. The net proceeds from the issuance were used to fund the purchase of the tendered Series A Bonds (discussed below), repay amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Tender Offer for General and Refunding Mortgage Bonds, Series A

On June 28, 2007, SPPC settled its cash tender offer, which commenced on June 15 and expired on June 22, 2007, for its 8.00% General and Refunding Mortgage Bonds, Series A, due 2008. Those holders who tendered their bonds by the expiration date were entitled to receive a purchase price of $1,022.10 per $1,000 principal amount of Series A Bonds. Approximately $220.8 million of the $320 million Series A Bonds outstanding were validly tendered and accepted by SPPC.

Washoe County Water Facilities Refunding Revenue Bonds

On April 27, 2007, on behalf of SPPC, Washoe County, Nevada (Washoe County) issued $80 million aggregate principal amount of its Water Facilities Refunding Revenue Bonds, Series 2007A and B, due March 1, 2036 (the “Water Bonds”).

In connection with the issuance of the Water Bonds, SPPC entered into financing agreements with Washoe County, pursuant to which Washoe County loaned the proceeds from the sales of the Water Bonds to SPPC. SPPC’s payment obligations under the financing agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series O.

The Water Bonds initial rates, as determined by auction on April 25, 2007, were 3.85%. The method of determining the interest rate on the Water Bonds may be converted from time to time so that the Water Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.

The proceeds of the offerings were used to refund the $80 million aggregate principal amount of 5.00% Washoe County Water Facilities Revenue Bonds, Series 2001, which had a mandatory remarketing in 2009.

Lease Commitments

NPC entered into a 20-year lease, with three 10-year renewal options, to occupy land and building for its Southern Operations Center (“Southern Ops lease”). In accordance with SFAS 13, “Accounting for Leases”, NPC accounts for the building portion of the lease as a capital lease and the land portion of the lease as an operating lease. As of June 30, 2007, NPC has recorded property of $15.2 million; however, NPC has not begun depreciation of the building as it continues to construct leasehold improvements and is not using the facilities as of June 30, 2007. NPC expects to transfer to the facilities in or around mid summer 2008. In addition, NPC is preparing to sublease portions of the building.

Minimum lease payments (capital lease portion) for the Southern Ops lease as of June 30, 2007 are as follows (dollars in thousands):

Remainder of 2007	$	222
2008		1,448
2009		1,470
2010		1,535
2011		1,558
Thereafter		31,805
Total minimum lease payments		38,038

Less amounts representing interest		22,515

Present value of net minimum lease payments	$	15,523

Minimum lease payments (operating lease portion) for the Southern Ops lease as of June 30, 2007 are as follows (dollars in thousands):

Remainder of 2007	$	65
2008		1,596
2009		1,567
2010		1,645
2011		1,661
Thereafter		34,222
Total operating lease payments	$	40,756

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 and SFAS No. 155. 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 purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value. A majority of the contracts entered into by the Utilities meet the criteria specified for this exception.

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 marketing of power and the procurement and marketing of natural gas. Derivative instruments used to manage energy price risk from time to time may include: 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.

Interest Rate Risk

In March 2007, SPPC entered into three forward-starting interest rate swap agreements, with an aggregate notional principal amount of $250 million, to manage the risk associated with changes in interest rates and the impact on future interest payments.

In June 2007, SPPC settled its three forward-starting interest rate swap agreements in connection with the issuance of $325 million of its 6.75% fixed rate General and Refunding Mortgage Notes, Series P, due 2037. SPPC received a gain of $11.3 million from the counterparty and recorded the amount as a premium on long term debt to be amortized over the life of the debt in accordance with regulatory accounting practices under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”).

NPC entered into and settled an interest rate lock agreement in June 2007, in connection with the issuance of $350 million of its 6.75% fixed rate General and Refunding Mortgage Notes, Series R, due 2037. NPC made a payment to the counterparty of $546 thousand and recorded the amount as a discount on long term debt to be amortized over the life of the debt in accordance with regulatory accounting practices under SFAS 71.

Risk Management Assets/Liabilities

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. The fair values of the open derivative positions are determined using quoted exchange prices, external dealer prices and available market pricing curves. 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, 2007										December 31, 2006
		Fair Value									Fair Value
		SPR			NPC			SPPC			SPR			NPC			SPPC

Risk management assets - current		$	36.8		$	25.7		$	11.1		$	27.3		$	16.4		$	10.9
Risk management assets - non-current			13.9			9.5			4.4			7.6			5.4			2.2
Total risk management assets			50.7			35.2			15.5			34.9			21.8			13.1

Risk management liabilities - current			76.2			54.9			21.3			123.1			84.7			38.4
Risk management liabilities - non-current			9.6			6.4			3.2			10.8			7.1			3.7
Total risk management liabilities			85.8			61.3			24.5			133.9			91.8			42.1

Less prepaid electric and gas options			28.9			21.0			7.9			23.9			13.9			10.1

Total Risk Management Regulatory (Asset)/Liability - net (1)		$	(64.0	)	$	(47.1	)	$	(16.9	)	$	(122.9	)	$	(83.9	)	$	(39.1	)

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

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities open derivative positions with its counterparties and the changes in forward commodity prices. The increase in risk management assets and the reduction of risk management liabilities as of June 30, 2007, as compared to December 31, 2006, is mainly due to favorable open 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 2007 relative to contract prices.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Reid Gardner Station

In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 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 NDEP Authorization to Discharge Permit issued October 2005.

Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $37 million. Expenditures for 2007 through 2010 are projected to be approximately $12 million. NPC is currently considering additional assessment plans to address historical groundwater impacts associated with facility operations; however, management cannot reasonably estimate costs at this time.

As disclosed in prior filings, in June 2006, the Environmental Protection Agency (EPA) issued a Finding and Notice of Violation (NOV) related to monitoring, recordkeeping and emission exceedances at the Reid Gardner facility. In April 2007, NPC lodged a Consent Decree in federal district court with NDEP, EPA and the Department of Justice (DOJ) regarding the NOVs and providing for additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that will be required to resolve the alleged violations. Terms of the Consent Decree include a $1.1 million fine, funding of projects, of which NPC expects to spend approximately $2 million for the Supplemental Environmental Project with the Clark County School District, and the installation of emission reduction equipment at the facility. The environmental project is aimed at achieving increased energy efficiency and cost savings. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations, and which will satisfy the terms of the consent decree, were previously submitted by NPC to the PUCN in NPC’s 2006 IRP filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen. Capital expenditures are estimated at $84.2 million as approved by the PUCN; however, amounts may change depending on the procurement of material and services.

Clark Station

In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Department of Air Quality and Environmental Management (DAQEM) entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. In October 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur. In May 2006, the EPA, by letter from the DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified civil penalties, together with injunctive relief, for alleged violations of the Prevention of Significant Deterioration requirements and Title V operating permit requirements of the Clean Air Act. NPC entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations and in June 2007, a Consent Decree between the parties was lodged in federal district court. Terms of the Consent Decree include installation of an advanced NOx reduction burner technology on four existing units with an estimated cost of up to $60 million, which cost was previously submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006 IRP filing and was approved in May 2007. Additionally, NPC will pay a minimal fine and make a contribution to Vegas Public Broadcasting Service (PBS) to fund a solar panel array on its new Educational Technology Campus planned in Clark County.

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 and sale.

Litigation

Nevada Power Company

Peabody Western Coal Company

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

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

On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On May 30, 2006, the Federal District Court remanded the case back to state court upon motion made by Peabody. On June 29, 2006, Joint Owners filed a motion to dismiss with the Missouri state court and requested a stay of the discovery proceedings pending the ruling on the new motion. On April 3, 2007, the Missouri state court denied Joint Owners’ motion to dismiss. Several discovery motions remain pending. NPC is unable to predict the outcome of the decisions.

In addition to the above action before the Missouri State court, Peabody further asserted in 1994 that Joint Owners are liable under the CSA for Retiree Health Care Costs (RHCC) and Final Reclamation Costs (FRC), which Peabody is obligated to pay after the CSA expires and the Kayenta Mine closes.

In 1996, SRP and the other Buyers 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 cannot recover RHCC and FRC until after the CSA ends. The case was dormant for several years, while Peabody pursued similar RHCC and FRC claims arising out of similar coal contracts. In January 2004, parties filed a joint motion to stay the litigation pending settlement discussions. The RHCC matter has not progressed from the early stages of litigation and remains stayed pursuant to court order until December 31, 2007. The FRC claim went to arbitration and parties remain in the early process of selecting a panel. Settlement discussions are continuous and ongoing. NPC is unable to predict the outcome of the settlement discussion.

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 (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 matter was taken under submission by the Court. A hearing on the renewed summary judgment motion is scheduled for August 8, 2007. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts or from other sources. Management has not recorded a loss contingency for this matter, as the loss, if any, can not be estimated at this time.

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.

Regulatory Contingencies

Nevada Power Company

Mohave Generation Station (Mohave)

NPC owns approximately 14% of the Mohave facility. Southern California Edison (SCE) is the operating partner of Mohave.

When operating, Mohave obtained all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal was delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of Mohave, alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. In 1999, the plant owners and plaintiffs filed a settlement with the court, which resulted in a consent decree, approved by the court in November 1999. The consent decree established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. Pursuant to the decree, Mohave Units 1 and 2 ceased operations as of January 2006 as the new emission limits were not met. Due to the lack of resolution regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the Consent Decree.

In December 2005, the Owners of the Mohave plant suspended operation, pending resolution of these issues. However, in June 2006, majority stake holder SCE announced it would no longer participate in the efforts to return the plant to service. As a result, NPC decided it is not economically feasible to continue its participation in the project. In September 2006, Salt River’s co-tenancy agreement expired and the operating agreement between the Owners expired in July 2006. The Owners are negotiating an extension of both agreements including a process that addresses how Owners may sell or assign their right, title, interest and obligations in Mohave.

In NPC’s 2003 GRC, the PUCN ordered the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its shutdown with recovery of any accumulated costs in a future rate case proceeding. As a result, NPC accumulated all costs and savings associated with the shut down of Mohave, including unrecovered plant costs, in Other Regulatory Assets. In NPC’s 2006 GRC, the PUCN approved the recovery of the net book value of the plant and costs and savings related to the plant through the certification period of October 31, 2006. The balance to be recovered, over an eight year period, is approximately $23.6 million as of June 30, 2007. All costs incurred subsequent to the certification period will continue to be accumulated in Other Regulatory Assets and NPC will seek recovery in its next GRC for those costs. The accumulated balance subsequent to the certification period is approximately $5.3 million as of June 30, 2007.

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

The difference, if any, between basic 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 EPS (dollars in thousands):

	Three months ended June 30,				Six months ended June 30,
	2007		2006		2007		2006
Basic EPS
Numerator

Net income applicable to common stock	$	25,754	$	27,836	$	41,361	$	29,078

Denominator
Weighted average number of common shares outstanding		221,412,345		200,897,101		221,329,347		200,882,857

Per Share Amounts

Net income applicable to common stock	$	0.12	$	0.14	$	0.19	$	0.14

Diluted EPS
Numerator

Net income applicable to common stock	$	25,754	$	27,836	$	41,361	$	29,078

Denominator(1)
Weighted average number of shares outstanding before dilution		221,412,345		200,897,101		221,329,347		200,882,857
Stock options		146,350		76,273		149,103		75,089
Executive long term incentive plan - restricted		-		105,060		-		108,567
Non-Employee Director stock plan		44,613		28,531		42,639		26,909
Employee stock purchase plan		4,471		2,347		3,807		2,453
Performance Shares		213,416		183,426		213,416		183,426
		221,821,195		201,292,738		221,738,312		201,279,301
Per Share Amounts

Net income applicable to common stock	$	0.12	$	0.14	$	0.19	$	0.14

(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, 2007 and 2006, 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, 2007, 581,074 and 727,949 shares, respectively, would be included and 942,908 and 933,433 shares, respectively, would be included for the three and six months ended June 30, 2006.

NOTE 8. PENSION AND OTHER POST-RETIREMENT BENEFITS

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

	For the three months ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006

Service cost	$	5,725		$	5,758		$	768		$	903
Interest cost		9,855			9,157			2,570			2,629
Expected return on plan assets		(10,474	)		(10,182	)		(1,309	)		(1,258	)
Amortization of prior service cost		407			473			30			31
Amortization of Transition Obligation		-			-			815			248
Amortization of net (gain)/loss		1,803			2,445			242			1,180
Special Termination Charges		-			-			-			-

Net periodic benefit cost	$	7,316		$	7,651		$	3,116		$	3,733


	For the six months ended June 30,
	Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006

Service cost	$	11,450		$	11,517		$	1,536		$	1,767
Interest cost		19,710			18,313			5,140			5,142
Expected return on plan assets		(20,948	)		(20,365	)		(2,618	)		(2,460	)
Amortization of prior service cost		814			946			61			61
Amortization of Transition Obligation		-			-			1,629			485
Amortization of net (gain)/loss		3,606			4,889			484			2,307
Special Termination Charges		-			-			-			-

Net periodic benefit cost	$	14,632		$	15,300		$	6,232		$	7,302

The amounts previously disclosed in Note 11, Retirement Plan and Post-retirement Benefits in the 2006 Annual Report on Form 10-K were $1.5 million for the pension plan and $12.5 million for other postretirement benefits, but it is likely that additional amounts will be funded to the retirement plan during the fourth quarter. Management will continue to reassess the amounts to be funded for each of the plans in 2007.

NOTE 9. DEBT COVENANT AND OTHER RESTRICTIONS

Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. As of June 30, 2007, NPC had paid $13.5 million in dividends to SPR and SPPC had paid $6.7 million in dividends to SPR in 2007. On August 7, 2007, NPC and SPPC declared a dividend to SPR of approximately $10 million and $5 million, respectively.

Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise may impact the amount of dividends that the Utilities may declare and pay. In June, 2007, the PUCN terminated the dividend restriction previously imposed by the PUCN in February 2006, which limited the amount of cash that NPC and SPPC could pay to SPR on a combined basis to actual cash necessary to service SPR’s debt for the year.

Debt agreements entered into by SPR and the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific agreements entered into by SPR and the Utilities, and restrictions on dividends contained in agreements to which they are party, as well as the effect of the Federal Power Act on the payment of dividends by the Utilities, are discussed in the 2006 Form 10-K, Note 8, Debt Covenant Restrictions in the Notes to Financial Statements.

As of June 30, 2007, SPR and the Utilities were able to pay dividends, subject to a cap, under the most restrictive test in their financing agreements; however, the total amount of dividends that SPR and the Utilities can pay under their financing agreements does not currently significantly restrict their ability to pay dividends.

NOTE 10. SUBSEQUENT EVENTS

On July 28, 2007, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share payable on September 12, 2007, to common shareholders of record on August 24, 2007. The dividend is the first dividend declared by SPR since February 2002.

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)

unseasonable weather and other natural phenomena, which, in addition to affecting NPC’s and SPPC’s (collectively referred to as the Utilities) customers’ demand for power, can have a potentially serious impact on the Utilities’ ability to procure adequate supplies of fuel or purchased power to serve their respective customers and on the cost of procuring such supplies;

(2)

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 and/or power or a ratings downgrade;

(3)

the effect that changes in environmental laws or regulations, including the imposition of significant new limits on emissions from electric generating facilities, such as requirements to reduce greenhouse gases and/or other pollutants in response to climate change legislation, may have on our existing operations as well as on our construction program, especially the proposed Ely Energy Center;

(4)

the effect that any construction risks may have on our business, such as the risk of delays in permitting, changes in environmental laws, securing adequate skilled labor, cost and availability of materials and equipment, equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(5)

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

(6)

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;

(7)

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

(8)

future economic conditions, including inflation rates and monetary policy;

(9)

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;

(10)

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;

(11)

changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities;

(12)

whether the Utilities will be able to continue to pay SPR dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act;

(13)

the discretion of SPR’s Board of Directors regarding SPR’s future common stock dividends based on the Board’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in SPR’s and the Utilities’ financing agreements;

(14)

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;

(15)

the final outcome of the proceedings to reverse the PUCN’s 2004 decision on SPPC’s 2003 General Rate Case, which disallowed the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project;

(16)

the timing and final outcome of the PUCN’s decision regarding SPPC’s recovery of deferred energy costs associated with claims for terminated supplier contracts;

(17)

employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages;

(18)

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

(19)

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;

(20)

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

(21)

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.

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 and the Utilities collectively), and includes the following for each of SPR, NPC and SPPC:

•

Results of Operations

•

Analysis of Cash Flows

•

Liquidity and Capital Resources

• Regulatory Proceedings (Utilities)

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 distribution, transmission, generation 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 Securities and Exchange Commission (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.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to the impacts of seasonal weather, rate changes and customer usage patterns on demand for electric energy and services. 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, with a slightly lower peak demand in the winter.

During the six months ended June 30, 2007, NPC’s revenues increased compared to the same period in 2006 primarily as a result of higher rates and customer growth. NPC’s net income for the six months ended June 30, 2007 increased compared to the same period in 2006 primarily due to the carrying charge for the Chuck Lenzie Generating Station (Lenzie) and the settlement with the PUCN regarding accrued interest on the 2001 deferred energy case. See Note 3, Regulatory Actions, in the Notes to Financial Statements and the 2006 Form 10-K.

During the six months ended June 30, 2007, SPPC’s electric revenues increased from the same period in 2006, while gas revenues dropped slightly. Electric revenues increased primarily as a result of higher rates and customer growth. Electric rates increased as a result of SPPC’s GRC and various deferred energy cases and Base Tariff Energy Rate (BTER) updates as discussed in the 2006 Form 10-K. SPPC’s gas revenues decreased primarily due to warmer weather in 2007 and a decrease in rates. SPPC’s net income for the second quarter of 2007 increased compared to the same period in 2006 primarily due to an increase in allowance for funds used during construction (AFUDC) and allowance for borrowed funds used during construction due to the construction at Tracy Generating Station and a decrease in interest charges.

SPR recognized net income applicable to common stock of $41.4 million for the six months ended June 30, 2007, compared to $29.1 million for the same period in 2006. Earnings increased primarily as a result of NPC’s carrying charge for Lenzie and the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case (see Note 3, Regulatory Actions, in the Condensed Notes to Financial Statements and the 2006 Form 10-K), and an increase in SPPC’s AFUDC and allowance for borrowed funds used during construction due to the construction at Tracy Generating Station and a decrease in interest charges.

Business Issues

SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core business. SPR’s and the Utilities’ strategies are aimed at owning more generating facilities, reducing dependence on purchased power and diversifying fuel mix while the Utilities’ service areas continue to grow. Growth in Nevada continues, although at a slower pace than in 2006. While growth in the State of Nevada, particularly in the Las Vegas area, has flattened out after the surge earlier this decade, the slower pace of housing starts has been partly offset by new casino projects in Las Vegas. Population growth forecasts, however, may be influenced by economic trends in hotel room expansion and changes in the local housing markets. The Utilities will continue to be subject to fluctuations in the volatile energy markets to the extent that the requirements of their customers are in excess of the Utilities’ owned generation, as well as, natural gas.

With significant amounts of construction costs in the Utilities’ future, SPR and the Utilities will need to raise substantial amounts of capital to fund expenditures. As a result, reducing the cost of capital by continuing to improve credit quality of the Utilities’ secured debt has been, and continues to be, a significant business focus for 2007.

Summarized below are significant business issues and challenges ahead in 2007. It is not intended to be an exhaustive discussion, nor to suggest that other issues may not arise during 2007 or thereafter. Details relating to the discussion below can be found in the Condensed Notes to the Financial Statements and elsewhere within this Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as the 2006 Form 10-K.

Generation Strategy

The Utilities’ Integrated Resource Plans (IRP) focuses on conventional generation, renewable energy, conservation, and transmission projects to meet Nevada’s growing electricity needs while diversifying the fuel mix of the Utilities’ generation portfolios. As a result, the Utilities have embarked on owning, constructing and purchasing energy to meet demand. NPC purchased and completed construction of Lenzie and purchased the Silverhawk facility, both of which are highly efficient natural gas burning generating stations. In 2007, NPC began construction of natural gas-fired combustion turbine peaking units at Clark Station to be in service for the summers of 2008 and 2009. SPPC is expanding its Tracy Generating Station. Both NPC and SPPC are working on the development and construction of the Ely Energy Center, consisting of two 750 MW coal-fired generation units and the Utilities continue to seek opportunities to purchase renewable energy.

Coal Generating Units

Included in the PUCN’s approval of the IRP is Phase 1 of the construction of the Ely Energy Center, a major project to be located near Ely, Nevada consisting of two 750 MW coal-fired generation units. In addition, the PUCN approved the development and construction of a 250-mile 500 kilovolt (kV) transmission line that will deliver electricity from the Ely Energy Center as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state. The PUCN approved spending up to $300 million for development activities associated with the Ely Energy Center; however, they placed a $155 million spending limit until the appropriate permits, as discussed below, are obtained. The PUCN established the project as a “critical facility,” thereby allowing it to qualify for incentives that will be determined in a later filing. Additionally, the PUCN required NPC and SPPC to file amendments to their IRPs once elements of the plan, including final costs, can be more accurately estimated. As filed with the PUCN, the estimated cost for the Ely Energy Center and the 500 kV transmission line is approximately $3.8 billion; however, depending on timing of construction, negotiations of certain contracts and permitting costs may differ. In addition to PUCN approval, the timing and construction of the Ely Energy Center is dependent, among other factors, on obtaining air permits from the Nevada Department of Environmental Protection and land use permits from the Bureau of Land Management. Possible changes to state and federal environmental laws or regulations, including those relating to carbon emissions from coal-fired power plants, could impact the permitting process and thereby affect the Utilities’ ability to proceed or could require design changes to the project. At this time we are unable to project when or if we will obtain the necessary permits and approvals. See “Risk Factors” below.

Natural Gas Generating Units

NPC has begun the construction of 600 MWs of natural gas-fired combustion turbine peaking units at Clark Station to be in service for the summers of 2008 and 2009 at an approximate cost of $395 million.

SPPC continues to construct a 541 MW gas fired high efficiency combined cycle generator at the Tracy Plant. SPPC anticipates an in-service date of June 2008. The PUCN ordered that SPPC be allowed to include construction work in progress balances in rate base between mandated general rate cases, prior to the in-service date, and granted a 1.5% enhanced Return on Equity (ROE) for the estimated $421 million investment. The unit will provide needed generation within SPPC’s control area to reliably serve the growing needs of Northern Nevada.

For more details of NPC’s and SPPC’s IRP, see the 2006 Form 10-K, Regulatory Proceedings, and Note 3, Regulatory Actions of the Condensed Notes to Financial Statements.

Renewable Energy

Nevada law sets forth the renewable energy portfolio standard (Portfolio Standard) requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable energy resources (Renewables). Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. In 2006, the Utilities were required to obtain 6% of their total energy from Renewables. The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources. In 2007 and 2008, the Utilities will be required to obtain 9% of their total energy from Renewables. The Utilities have embarked on a strategy to invest in renewable energy that, along with third party contracts, and an increase in qualified conservation programs, will provide the opportunity for the Utilities to meet the Portfolio Standard as set forth by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewable energy resources.

In the second quarter 2007, Nevada Solar One, owned by Acciona Solar Power, the largest-capacity solar power plant built in the world in 16 years and the third-largest of its kind began supplying power to the Nevada Power Grid. All of the plant’s electricity production is being sold to NPC and SPPC under long-term power purchase agreements.

Management of Energy Risk

The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. While NPC has greatly reduced its dependence on wholesale power markets to meet its customers’ demand, both Utilities continue to have a significant need to tap energy markets due to the fact that the Utilities’ owned generation is insufficient to meet their customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk, the prospect that energy supplies will not be sufficient to fulfill customer requirements.

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

The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. Reference details of the Utilities’ energy supply plan in their 2006 Form 10-K. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.

The Utilities follow PUCN-approved energy supply plans that encompass the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for economic hedging in conjunction with energy purchases and sales are also used to mitigate these risks. The Utilities do not trade financial instruments.

Access to Capital Markets

With substantial commitments to existing and prospective construction and exposure to volatile energy costs, SPR and the Utilities’ access to capital markets, including both debt and equity, continues to be a significant business issue. Management continues to be focused on improving the credit quality of the Utilities’ senior secured debt to investment grade credit. Significant amounts of capital may be necessary to fund construction costs of generating units and, as a result, management may be required 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 capital contributions from 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 issue more debt to support their operating costs or may need to delay capital expenditures.

Regulatory

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. The Utilities remain committed to maintaining a positive relationship with their regulators. Details regarding recently approved and pending rate cases are discussed in Note 3, Regulatory Actions, of the Condensed Notes to Consolidated Financial Statements.

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 $21.3 million and $25.9 million of long term debt interest costs for the six months ended June 30, 2007 and 2006, respectively.

During the three months ended June 30, 2007, SPR’s recognized net income applicable to common stock of approximately $25.8 million compared to $27.8 million for the same period in 2006. The decrease in earnings is primarily due to:

·	an increase in operating expenses;

·	a decrease on interest accrued on deferred energy due to lower deferred energy balances;

·	a decrease in other income primarily associated with a decrease in the amortization of gains associated with the disposition of property at NPC; and

·	an increase in other expense primarily associated with NPC’s costs associated with the Reid Gardner consent decree.

These decreases to net income applicable to common stock were partially offset by an increase in operating revenues and a decrease in interest charges.

During the six months ended June 30, 2007, SPR recognized net income applicable to common stock of approximately $41.4 million compared to $29.1 million for the same period in 2006. The change in SPR’s consolidated earnings during the six months ended June 30, 2007, compared to the same period in 2006, was primarily due to a decrease in interest charges at SPPC and the Holding Company, the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case, the carrying charge for Lenzie and an increase in SPPC’s AFUDC and allowance for borrowed funds used during construction due to construction at the Tracy Generating Station.

As of June 30, 2007, NPC and SPPC had paid $13.5 million and $6.7 million, respectively, in dividends to SPR in 2007. On August 7, 2007, NPC and SPPC declared a dividend to SPR of $10 million and $5 million, respectively.

ANALYSIS OF CASH FLOWS

Cash flows increased during the six months ended June 30, 2007, compared to the same period in 2006, due to an increase in cash from operating activities, offset by an increase in cash used in investing activities and a decrease in cash from financing activities.

Cash flows from operating activities increased during the six months ended June 30, 2007, compared to the same period in 2006, primarily due to increases in customer rates, a decrease in payments made to suppliers, the timing of payments, improved credit terms with vendors, lower interest payments due to various refinancings of debt in 2006, and the net settlement with Enron in 2006.

Cash flows used by investing activities increased during the six months ended June 30, 2007, when compared to the same period in 2006, due to construction activities for NPC’s Clark Peaking Units and the Centennial Transmission Line and SPPC’s Tracy Generating Station expansion, offset partially by the completion of construction at Lenzie and the purchase of the Silverhawk Generating Station in 2006.

Cash flows from financing activities decreased during the six months ended June 30, 2007, when compared to the same period in 2006, due to a decrease in financing activities as a result of the utilization of cash generated from operating activities, the completion of construction at Lenzie and the purchase of the Silverhawk Generating Station which required significant amounts of capital in 2006. Partially offsetting the decrease in cash flows from financing activities was a reduction in the redemption and retirement of debt.

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 and interest.

Available Liquidity as of June 30, 2007 (in millions)
	SPR		NPC		SPPC
Cash and cash equivalents	$	22.9	$	28.8	$	93.9
Balance available on revolving credit facility	N/A			436.8		331.0

	$	22.9	$	465.6	$	424.9

SPR has approximately $42.5 million payable of debt service obligations for 2007, of which SPR paid approximately $21.3 million during the six months ended June 30, 2007. SPR has approximately $21.2 million payable of debt service obligations remaining during 2007. On July 28, 2007, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share payable on September 12, 2007 to common shareholders of record on August 24, 2007. The amount payable will be approximately $17.8 million, which SPR expects to pay using cash on hand. The dividend is the first dividend declared by SPR since February 2002. SPR expects to meet its debt service obligations with cash on hand and/or through dividends from the Utilities. See Dividends from Subsidiaries below.

SPR and the Utilities anticipate that they will be able to meet operating costs such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy and external borrowings. To manage liquidity needs, as a result of seasonal peaks in fuel requirement, SPR and the Utilities may use hedging activities. However, to fund capital requirements, as discussed in the 2006 Form 10-K, SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the six months ended June 30, 2007, there were no material changes to contractual obligations as set forth in SPR’s 2006 Form 10-K for SPR (holding company). See NPC and SPPC’s respective sections for changes in contractual obligations.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of June 30, 2007, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $74.2 million of its unsecured 7.803% Senior Notes due 2012; $225 million of its 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, 2007, SPR, NPC, SPPC and their subsidiaries had approximately $4.4 billion of debt and other obligations outstanding, consisting of approximately $2.66 billion of debt at NPC, approximately $1.19 billion of debt at SPPC and approximately $549 million of debt at the holding company. 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 NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise may impact the amount of dividends that the Utilities may declare and pay. In June, 2007, the PUCN terminated the dividend restriction previously imposed by the PUCN in February 2006 which limited the amount of cash that NPC and SPPC could pay to SPR on a combined basis to actual cash necessary to service SPR’s debt for the year.

Credit Ratings

SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations: Standard & Poor’s (S&P), Moody’s Investors Service, Inc. (Moody’s), Fitch Ratings Ltd. (Fitch), and Dominion Bond Rating Service (DBRS). As of August 3, 2007 the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPR	Sr. Unsecured Debt	BB (low)	BB-	B1	B
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	B
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+

* Ratings are investment grade

In June 2007, Moody’s placed the senior unsecured debt at SPR, and the senior secured debt at NPC and SPPC, under review for possible upgrade. Also in June 2007, S&P and Fitch revised their outlook on all three companies to Positive from Stable. In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to SPR, NPC and SPPC. The ratings for the senior secured debt of NPC and SPPC are BBB (low), which is the minimum level for investment grade. The rating assigned to SPR’s senior notes is BB (low), which is non-investment grade. DBRS’s trend for all three companies is Stable.

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.

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 that the Utility maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that the Utility maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2007, both Utilities were in compliance with these covenants.

Limitations on Indebtedness

The terms of SPR’s $250 million 8.625% Senior Unsecured Notes due March 15, 2014, $74.2 million 7.803% Senior Unsecured Notes due 2012 and $225 million 6.75% Senior Unsecured Notes due 2017 restrict SPR and NPC and SPPC from incurring any additional indebtedness unless:

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

the debt incurred is specifically permitted under the terms of the respective series of Senior Notes, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit supporting SPR’s or any Restricted Subsidiary’s obligations to energy suppliers; or

3.	the indebtedness is incurred to finance capital expenditures pursuant to NPC’s and SPPC’s Integrated Resource Plan, as approved or amended under order by the PUCN.

If the respective series of Senior Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the respective series of Senior Notes remain investment grade. As of June 30, 2007, SPR, NPC and SPPC would have been able to issue approximately $2.0 billion of additional indebtedness on a consolidated basis, assuming an interest rate of 7%, per the requirement stated in number 1 above.

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.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2007, NPC recognized net income of approximately $23.6 million compared to net income of approximately $28.5 million for the same period in 2006. During the six months ended June 30, 2007, NPC recognized net income of approximately $28.2 million compared to net income of approximately $25.2 million for the same period in 2006.

During the six months ended June 30, 2007, NPC paid $13.5 million in dividends to SPR. On August 7, 2007, NPC declared a dividend to SPR of $10 million.

Gross margin is presented by NPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, 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.

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 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 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. 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							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Operating Revenues:
Electric	$	575,108	$	543,869		5.7	%	$	993,273	$	925,144		7.4	%

Energy Costs:
Purchased power		175,716		187,093		-6.1	%		271,310		348,689		-22.2	%
Fuel for power generation		140,773		151,694		-7.2	%		304,858		241,516		26.2	%
Deferral of energy costs-electric-net		67,731		30,621		121.2	%		94,663		33,788		180.2	%
		384,220		369,408		4.0	%		670,831		623,993		7.5	%

Gross Margin	$	190,888	$	174,461		9.4	%	$	322,442	$	301,151		7.1	%

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

Electric Operating Revenue

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Electric Operating Revenues:
Residential	$	267,060	$	250,459		6.6	%	$	446,309	$	408,354		9.3	%
Commercial		122,130		115,191		6.0	%		218,033		203,127		7.3	%
Industrial		167,520		163,573		2.4	%		292,346		277,528		5.3	%
Retail revenues		556,710		529,223		5.2	%		956,688		889,009		7.6	%
Other (1)		18,398		14,646		25.6	%		36,585		36,135		1.2	%
Total Revenues	$	575,108	$	543,869		5.7	%	$	993,273	$	925,144		7.4	%

Retail sales in thousands
Of megawatt-hours (MWh)		5,588		5,460		2.3	%		9,782		9,461		3.4	%

Average retail revenue per MWh	$	99.63	$	96.93		2.8	%	$	97.80	$	93.97		4.1	%

¹ Primarily wholesale, as discussed below.

NPC’s retail revenues increased for the three and six months ended June 30, 2007, as compared to the same period in 2006, due to increases in retail rates and customer growth. Retail rates increased as a result of NPC’s various Base Tariff Energy Rate (BTER) and Deferred Energy Cases and NPC 2006 GRC, effective June 1, 2007 (see Note 3, Regulatory Actions of the Condensed Notes to Financial Statements and in the 2006 Form 10-K, Management’s Discussion and Analysis, Regulatory Proceedings, for details). Retail customers increased by 3.2%, and 3.4% for the three and six months ended June 30, 2007, respectively.

Electric Operating Revenues – Other increased for the three months ended June 30, 2007 compared to the same period in 2006 primarily due to a decrease in the reclassification of revenues in 2007 associated with Mohave which have been 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 6, Commitments and Contingencies in the Notes to Financial Statements.

Electric Operating Revenues – Other increased slightly for the six months ended June 30, 2007 compared to the same period in 2006 primarily due to a decrease in the reclassification of Mohave, as described above, partially offset by a decrease in energy usage by Public Authority customers due to their transitioning to distribution only services by purchasing their energy from other sources, as allowed by Nevada law under certain circumstances, and a change in contract terms with certain other customers.

Purchased Power

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %

Purchased Power	$	175,716	$	187,093		-6.1	%	$	271,310	$	348,689		-22.2	%

Purchased Power in thousands
of MWhs		2,369		2,599		-8.8	%		3,552		4,899		-27.5	%
Average cost per MWh of
purchased power	$	74.17	$	71.99		3.0	%	$	76.38	$	71.18		7.3	%

NPC’s purchased power costs and megawatt hours (MWhs) decreased for the three and six months ended June 30, 2007 compared to the same periods in 2006 primarily due to a decrease in volume. Volume decreased as a result of NPC’s increased reliance on internal generation, which was more economical than purchased power. Although natural gas costs increased, the average cost per MWh increased primarily due to fixed capacity charges coupled with a decrease in volume.

Fuel For Power Generation

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %

Fuel for power generation	$	140,773	$	151,694		-7.2	%	$	304,858	$	241,516		26.2	%

Thousands of MWhs generated		3,556		3,286		8.2	%		6,934		5,215		33.0	%
Average cost per MWh of
generated power	$	39.59	$	46.16		-14.2	%	$	43.97	$	46.31		-5.1	%

Fuel for power generation decreased for the three months ended June 30, 2007 as compared to the same time period in 2006 primarily due to lower natural gas prices and lower option costs, partially offset by the effect of higher volumes purchased. The volume purchased increased due to the increased reliance on internal generation, as it was more economical than the cost of purchased power. The average cost per MWh decreased primarily due to lower natural gas prices and the increased usage of Lenzie Block 1 and 2, which were placed in service in February and April 2006. Lenzie is a 1200 MW (nominally rated) natural gas-fired high efficiency combined cycle power plant.

Fuel for power generation increased for the six months ended June 30, 2007 as compared to the same time period in 2006 primarily due to an increase in volume. As discussed above, volume primarily increased due to reliance on internal generation. In addition, an increase in NPC’s total system of approximately 3.7% partially contributed to the increase in volume. The average cost per MWh of generation for this period decreased primarily due to lower natural gas prices and the increased usage of Lenzie, as discussed above.

Deferred Energy Costs - Net

	Three Months							Six Months
	Ended June 30,							Ended June 30,
	2007		2006		Change from Prior Year %			2007		2006		Change from Prior Year %

Deferred energy costs - net	$	67,731	$	30,621		121.2	%	$	94,663	$	33,788		180.2	%

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

Amounts for the three months ended June 30, 2007 and 2006 include amortization of deferred energy costs of $40.6 million and $31.1 million, respectively; and an over-collection of amounts recoverable in rates of $27.1 million in 2007, compared to an under-collection of $0.5 million in 2006. Amounts for the six months ended June 30, 2007 and 2006 include amortization of deferred energy costs of $64.7 million and $52.4 million, respectively; and an over-collection of amounts recoverable in rates of $29.9 million in 2007, compared to an under-collection of $18.6 million in 2006.

Allowance for Funds Used During Construction (AFUDC)

	Three Months							Six Months
	Ended June 30,							Ended June 30,
	2007		2006		Change from Prior Year %			2007		2006		Change from Prior Year %

Allowance for other funds
used during construction	$	3,247	$	2,725		19.2	%	$	6,345	$	8,154		-22.2	%

Allowance for borrowed funds used during construction	$	2,703	$	2,700		0.1	%	$	5,253	$	8,072		-34.9	%
	$	5,950	$	5,425		9.7	%	$	11,598	$	16,226		-28.5	%

AFUDC increased for the three months ended June 30, 2007, compared to the same period in 2006 primarily due to the start of construction of the Clark Peaking Units in 2007.

AFUDC decreased for the six months ended June 30, 2007, compared to the same period in 2006, due to the completion of construction of Lenzie Blocks 1 and 2 and the Harry Allen Unit in 2006. Lenzie Blocks 1 and 2 were completed in January and April 2006, respectively and Harry Allen was completed in May 2006.

Other (Income) and Expenses

	Three Months									Six Months
	Ended June 30,									Ended June 30,
	2007			2006			Change from Prior Year %			2007			2006			Change from Prior Year %

Other operating expense	$	55,162		$	47,705			15.6	%	$	106,001		$	101,838			4.1	%
Maintenance expense	$	20,319		$	14,431			40.8	%	$	37,783		$	28,588			32.2	%
Depreciation and amortization	$	38,833		$	34,884			11.3	%	$	74,594		$	69,121			7.9	%
Interest charges on long-term debt	$	41,368		$	46,191			-10.4	%	$	81,074		$	88,930			-8.8	%
Interest charges-other	$	5,603		$	3,464			61.7	%	$	12,439		$	7,291			70.6	%
Interest accrued on deferred energy	$	(3,427	)	$	(6,126	)		-44.1	%	$	(7,276	)	$	(12,909	)		-43.6	%
Carrying charge for Lenzie	$	(5,998	)	$	(9,135	)		-34.3	%	$	(16,080	)	$	(13,166	)		22.1	%
Reinstated interest on deferred energy		-			-		N/A			$	11,076			-		N/A
Other income	$	(2,909	)	$	(4,385	)		-33.7	%	$	(8,030	)	$	(8,751	)		-8.2	%
Other expense	$	5,384		$	2,338			130.3	%	$	7,426		$	4,303			72.6	%

Other operating expense increased for the three and six months ended June 30, 2007, compared to the same periods in 2006. In 2007, operating expenses increased as a result of higher operating expenses for Lenzie and Navajo, increased costs for claims and legal fees, partially offset by the reversal of Enron legal fees, which are now being recovered in rates as a result of NPC’s Western Energy Crisis Rate Case, see Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for further discussion, and the reversal of consulting fees. Additionally, in 2006, operating expenses were lower primarily as a result of the settlement of contingency fees associated with Enron and, in the case of the three months ended June 30, 2006, the reclassification of operating expenses related to Mohave to a regulatory asset as ordered by the PUCN.

Maintenance expense increased for the three months ended June 30, 2007, compared to the same period in 2006, mainly due to forced outages at Harry Allen and costs incurred at Lenzie for construction repairs.

Maintenance expense increased for the six months ended June 30, 2007, compared to the same period in 2006, mainly due to the operation of Lenzie Units 1 and 2, which were placed in service in January 2006 and April 2006, respectively, the timing of outages at Reid Gardner (forced outages and accelerated maintenance in 2007 and deferred maintenance in 2006) and forced outage at Harry Allen in 2007, partially offset by scheduled and forced outages at Clark Station in 2006.

Depreciation and amortization expenses increased during the three months and six months ended June 30, 2007, compared to the same periods in 2006, primarily as a result of the inclusion of Lenzie in depreciation as of June 2007 as a result of NPC’s 2006 GRC, an adjustment for Silverhawk depreciation based on regulatory clarification, and an increase to plant-in-service for Harry Allen Unit IV in May 2006.

Interest charges on long-term debt decreased during the three months and six months ended June 30, 2007, compared to the same period in 2006, due primarily to various re-financings of debt in 2006 at lower interest rates and a decrease in the use of the Revolving Credit Facility in the first six months of 2007. The increase in use of the Revolving Credit Facility in 2006 was primarily due to increased capital expenditures and fuel and purchased power expenses in 2006. Interest expense for the Revolving Credit Facility for the three and six months ended June 30, 2007, was approximately $2.5 million and $3.6 million respectively, compared to $4.4 million and $7.9 million, respectively, for the same periods in the prior year. See the 2006 Form 10-K, Note 6, Long-Term Debt of the Notes to Financial Statements, for additional information regarding long-term debt and Note 4, Long-Term Debt of the Condensed Notes to Financial Statements.

Interest charges-other increased for the three months and six months ended June 30, 2007, as compared to the same periods in 2006, due to amortization of debt redemption costs, as well as additional interest associated with customer transmission deposits and new property leases.

Interest accrued on deferred energy costs decreased for the three months and six months ended June 30, 2007 due to lower deferred energy balances compared to the same periods in 2006. See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Carrying charges for Lenzie represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. Carrying charges decreased for the three months ended June 30, 2007 as compared to the same period in 2006, as a result on NPC’s 2006 GRC, which includes the cost of Lenzie in rates. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for discussion of the accounting for the carrying charge for Lenzie and Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for discussion of NPC’s 2006 GRC.

Carrying charges increased for the six months ended June 30, 2007, as compared to the same period in 2006, due to the timing of commercial operation of the Units. Lenzie Units 1 and 2 of this station were commercially operable in January 2006 and April 2006.

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, the PUCN approved a settlement agreement allowing NPC to recover past carrying charges.

Other income decreased for the three months and six months ended June 30, 2007, as compared to the same periods in 2006, due to lower interest income and the adjustment and expiration of the amortization of gains associated with the disposition of property.

Other expense increased during the three months and six months ended June 30, 2007, compared to the same periods in 2006, primarily due to costs associated with the Energy Savings Project for the Clark County School District, as agreed upon in the Reid Gardner Consent Decree discussed in Note 6, Commitments and Contingencies of the Condensed Notes to Financial Statements.

ANALYSIS OF CASH FLOWS

Cash flows increased during the six months ended June 30, 2007, when compared to the same period in 2006, due to an increase in cash from operations and a decrease in cash used in investing activities, offset by a reduction in cash from financing activities.

Cash flows from operating activities increased during the six months ended June 30, 2007, compared to the same period in 2006, primarily due to increased rates, a decrease in payments made to suppliers, the timing of payments, improved credit terms with vendors and the net settlement with Enron in 2006.

Cash flows for investing activities decreased during the six months ended June 30, 2007, compared to the same period in 2006, primarily due to the completion of construction at Lenzie and the purchase of the Silverhawk generating station in 2006 offset by expenditures for the Clark Peaking Units and the Centennial Transmission Line.

Cash flows from financing activities decreased during the six months ended June 30, 2007, when compared to the same period in 2006, due to a decrease in financing activities. Financing activities decreased as a result of the utilization of cash generated from operating activities and the completion of construction at Lenzie and the purchase of the Silverhawk Generating Station in 2006, which required significant amounts of capital. Partially offsetting this decrease was a decrease in retirement of debt and dividends paid to SPR.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows are 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 and the payment of interest on NPC’s outstanding indebtedness.

Available Liquidity as of June 30, 2007 (in millions)
Cash and cash equivalents	$	28.8
Balance available on Revolving Credit Facility (1)		436.8
	$	465.6

¹_{As
of
August 6, 2007, NPC had approximatey $461.8 million available under its
revolving credit facility. Additionally, if necessary, NPC has the ability
to issue additional debt , as discussed under Limitations of
Indebtedness.}

NPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and external borrowings. However, to fund capital requirements, NPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the six months ended June 30, 2007, there were no material changes to the contractual obligations described in NPC’s 2006 Form 10-K, except for construction contracts entered into in January 2007 related to NPC’s peaking units at Clark Station for approximately $350.6 million.

Financing Transactions

6.75% General and Refunding Mortgage Notes, Series R

On June 28, 2007, NPC issued and sold $350 million of its 6.750% General and Refunding Mortgage Notes, Series R, due July 1, 2037. The Series R Notes were issued pursuant to a registration statement previously filed with the Securities and Exchange Commission. The net proceeds from the issuance were used to fund the purchase of the tendered Series G Notes (discussed below), repay amounts outstanding under NPC’s revolving credit facility, and for general corporate purposes.

Tender Offer for General and Refunding Mortgage Notes, Series G

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 that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2007, NPC was in compliance with these covenants.

Limitations on Indebtedness

Certain factors impact NPC’s ability to issue debt:

Financing Authority from the PUCN: On June 22, 2007, NPC received PUCN authorization to enter into financings of $3.91 billion through 2009. Of this total, $1.35 billion is contingent upon the PUCN’s approval of the Ely Energy Center in 2008. The remaining authority, $2.56 billion, includes authority for the revolving credit facility, and authority to issue new debt and to refinance existing debt. As of June 30, 2007, NPC used approximately $950 million of the $2.56 billion authority, as such approximately $1.6 billion of the authority remains.

Limits on Bondable Property: 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 the General and Refunding Mortgage Indenture. As of June 30, 2007, NPC had the capacity to issue $655 million of General and Refunding Mortgage Securities.

3.	Financial Covenants in its financing agreements.

The terms of certain SPR debt further prohibit NPC and SPPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of NPC’s Series G Notes, which mature in 2013, NPC’s Series I Notes, which mature in 2012, NPC’s Series L Notes, which mature in 2015, and NPC's Second Amended and Restated Revolving Credit Facility restrict NPC from incurring any additional indebtedness unless certain covenants are satisfied. See the 2006 Form 10-K, Note 8, Debt Covenant Restrictions of the Notes to Financial Statements. If NPC’s Series G Notes, Series I Notes, or the Series L Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of securities remains investment grade.

As of June 30, 2007, the financial covenants under the revolving credit facility, which are more restrictive than the Series G, I and L Notes restrictions, would allow NPC to issue up to $2.0 billion of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, of $2.0 billion as of June 30, 2007. Therefore, NPC would not be materially limited by SPR’s cap on additional indebtedness.

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 $2.0 billion, depending on the Utilities’ combined usage of their respective revolving credit facilities at the time of the covenant calculation.

Limitations on Ability to Issue General and Refunding Mortgage Bonds

NPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of June 30, 2007, $2.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (2) above under “Limitations on Indebtedness,” $655 million of additional securities may be issued under the General and Refunding Mortgage Indenture as of June 30, 2007. That amount is determined on the basis of:

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

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.

Credit Ratings

NPC is rated by four Nationally Recognized Statistical Rating Organizations: S&P, Moody’s, Fitch, and DBRS. As of August 3, 2007 the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	B

* Ratings are investment grade

In June 2007, Moody’s placed the senior secured debt at NPC under review for possible upgrade and S&P and Fitch revised their outlook on the company to Positive from Stable. In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to NPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment grade. DBRS’s trend for the company is Stable.

Cross Default Provisions

None of the financing agreements of NPC contain a cross default provision that would result in an event of default by NPC upon an event of default by SPR or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2007, SPPC recognized earnings applicable to common stock of approximately $10.0 million compared to $7.6 million for the same period in 2006. During the six months ended June 30, 2007, SPPC recognized earnings applicable to common stock of approximately $32.0 million compared to $19.9 million for the same period in 2006.

During the six months ended June 30, 2007, SPPC paid $6.7 million in dividends to SPR. On August 7, 2007, SPPC declared a dividend to SPR of $5 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. 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							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Operating revenues:
Electric	$	245,356	$	244,022		0.5	%	$	498,235	$	482,794		3.2	%
Gas		31,378		33,297		-5.8	%		116,498		120,022		-2.9	%
	$	276,734	$	277,319		-0.2	%	$	614,733	$	602,816		2.0	%

Energy costs:
Purchased power	$	86,309	$	69,608		24.0	%	$	169,619	$	161,756		4.9	%
Fuel for power generation		51,285		62,474		-17.9	%		115,354		115,761		-0.4	%
Deferral of energy costs-electric-net		18,770		22,328		-15.9	%		32,631		23,233		40.5	%
Gas purchased for resale		19,862		24,352		-18.4	%		91,508		91,748		-0.3	%
Deferral of energy costs-gas-net		3,554		1,353		162.7	%		1,609		6,084		-73.6	%
	$	179,780	$	180,115		-0.2	%	$	410,721	$	398,582		3.0	%
Energy costs by segment:
Electric	$	156,364	$	154,410		1.3	%	$	317,604	$	300,750		5.6	%
Gas		23,416		25,705		-8.9	%		93,117		97,832		-4.8	%
	$	179,780	$	180,115		-0.2	%	$	410,721	$	398,582		3.0	%

Gross margin by segment:
Electric	$	88,992	$	89,612		-0.7	%	$	180,631	$	182,044		-0.8	%
Gas		7,962		7,592		4.9	%		23,381		22,190		5.4	%
	$	96,954	$	97,204		-0.3	%	$	204,012	$	204,234		-0.1	%

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			Six Months
	Ended June 30,			Ended June 30,
			Change from Prior Year %			Change from Prior Year %
	2007	2006	Change from Prior Year %	2007	2006	Change from Prior Year %
Electric operating revenues:
Residential	$ 70,347	$ 68,217	3.1%	$ 158,356	$ 150,581	5.2%
Commercial	95,872	91,404	4.9%	182,872	173,238	5.6%
Industrial	71,433	75,957	-6.0%	141,874	142,317	-0.3%
Retail revenues	237,652	235,578	0.9%	483,102	466,136	3.6%
Other (1)	7,704	8,444	-8.8%	15,133	16,658	-9.2%
Total revenues	$ 245,356	$ 244,022	0.5%	$ 498,235	$ 482,794	3.2%

Retail sales in thousands
of megawatt-hours (MWh)	2,088	2,101	-0.6%	4,238	4,170	1.6%

Average retail revenue per MWh	$ 113.82	$ 112.13	1.5%	$ 113.99	$ 111.78	2.0%

¹ Primarily wholesale, as discussed below.

SPPC’s retail revenues increased for the three and six months ended June 30, 2007, as compared to the same periods in the prior year primarily due to customer growth and increases in retail rates. The number of retail customers increased by 2.1%, and 2.3% for the three and six months ended June 30, 2007, respectively. Retail rates increased as a result of SPPC’s various general, energy, and deferred energy cases. For details see the 2006 Form 10-K, Management’s Discussion and Analysis, Regulatory Proceedings. These increases were offset by lower industrial energy revenues and MWhs as a result of two large industrial customers moving to distribution-only and standby service.

The decrease in Electric Operating Revenues – Other for the three and six months ended June 30, 2007, compared to the same period in 2006 was primarily due to the decreased wheeling revenues and a decrease in charges related to the departure of Barrick Gold from SPPC’s system.

Gas Operating Revenues

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Gas operating revenues:
Residential	$	17,496	$	18,244		-4.1	%	$	65,208	$	67,533		-3.4	%
Commercial		8,492		8,995		-5.6	%		31,839		31,738		0.3	%
Industrial		3,706		3,997		-7.3	%		11,005		11,748		-6.3	%
Retail revenues		29,694		31,236		-4.9	%		108,052		111,019		-2.7	%
Wholesale revenue		1,063		1,351		-21.3	%		6,979		7,500		-6.9	%
Miscellaneous		621		710		-12.5	%		1,467		1,503		-2.4	%
Total revenues	$	31,378	$	33,297		-5.8	%	$	116,498	$	120,022		-2.9	%

Retail sales in thousands
of decatherms		2,191		2,339		-6.3	%		8,479		8,680		-2.3	%

Average retail revenue per decatherm	$	13.55	$	13.35		1.5	%	$	12.74	$	12.79		-0.4	%

SPPC’s retail gas revenues decreased for the three and six months ended June 30, 2007, as compared to the same periods in the prior year primarily due to warmer winter temperatures during 2007 and decreases in retail customer rates. Retail rates decreased as a result of SPPC’s Gas GRC and 2006 Natural Gas and Propane Deferred Rate Case and BTER update. For details see the 2006 Form 10-K, Management’s Discussion and Analysis, Regulatory Proceedings. Partially offsetting these decreases was an increase in retail customers of 3.3% and 3.5% for the three and six months ended June 30, 2007, respectively.

On May 15, 2007, SPPC filed an application with the PUCN to implement a new deferred energy account adjustment in order to recover natural gas costs and to reset the BTER. If approved by the PUCN, SPPC has requested rates to become effective December 2007. See Note 3, Regulatory Actions, in the Condensed Notes to Financial Statements.

The wholesale revenues for the three and six months ended June 30, 2007 decreased from the same periods in 2006 primarily due to decreased availability of gas for wholesale sales.

Purchased Power

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %

Purchased power	$	86,309	$	69,608		24.0	%	$	169,619	$	161,756		4.9	%

Purchased power in thousands
of MWhs		1,450		1,389		4.4	%		2,780		2,704		2.8	%
Average cost per MW of
purchased power	$	59.52	$	50.11		18.8	%	$	61.01	$	59.82		2.0	%

Purchased power costs increased for the three and six months ended June 30, 2007 as compared to the same periods in 2006 primarily due to an increase in natural gas prices. Volumes for the three and six months ended June 30, 2007 increased due to a slight increase in SPPC’s total system demand.

The average cost per MWh for purchased power was less than the average fuel cost per MWh to generate power; however, to purchase additional power was not necessarily more cost effective than the use of our internal generation. During the six months ended June 30, 2007, SPPC was able to purchase power received through Idaho Power’s transmission system at lower rates. However, Idaho Power’s limited transmission capacity constrains SPPC’s ability to purchase additional power at those lower rates. As such, additional power purchases would require delivery from California, which was not as cost effective or materially different than the cost to generate power.

Fuel For Power Generation

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %

Fuel for power generation	$	51,285	$	62,474		-17.9	%	$	115,354	$	115,761		-0.4	%

Thousands of MWh generated		808		821		-1.6	%		1,761		1,744		1.0	%
Average fuel cost per MWh
of generated power	$	63.47	$	76.10		-16.6	%	$	65.50	$	66.38		-1.3	%

Fuel for power generation and the average cost per MWh decreased for the three months ended June 30, 2007, as compared to the same period in 2006 due to the decrease in the cost of hedging instruments. Fuel for power generation for the six months ended June 30, 2007 was comparable to the same period in 2006.

Average cost per MWh for fuel for generation compared to the average cost per MWh for purchase power was higher, primarily due to outages at Valmy, which required the use of less efficient generation. Additionally, SPPC was able to purchase power for off-peak at significantly lower prices, lowering the average cost per MWh for purchased power. However, as discussed above under purchased power, SPPC was limited in the ability to purchase more energy due to transmission restraints.

Gas Purchased for Resale

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %

Gas purchased for resale	$	19,862	$	24,352		-18.4	%	$	91,508	$	91,748		-0.3	%

Gas purchased for resale
(in thousands of decatherms)		2,322		2,549		-8.9	%		9,795		10,006		-2.1	%

Average cost per decatherm	$	8.55	$	9.55		-10.5	%	$	9.34	$	9.17		1.9	%

Gas purchased for resale and the average cost per decatherm decreased for the three months ended June 30, 2007 as compared to the same period in 2006 due to the impact of the settlement of hedging instruments in the second quarter of 2006. The volume of gas purchased for resale decreased for the three months ended June 30, 2007 as compared to the same period in 2006 due to a decrease in usage due to warmer temperatures in 2007.

Gas purchased for resale for the six months ended June 30, 2007 was comparable to the same period in 2006. However, the average cost per decatherm increased slightly as a result of settlements of hedging instruments in 2007. In addition, in the same period 2006, SPPC settled hedging transactions which resulted in a decrease in gas purchased for resale costs.

Deferred Energy Costs

	Three Months							Six Months
	Ended June 30,							Ended June 30,
	2007		2006		Change from Prior Year %			2007		2006		Change from Prior Year %

Deferred energy costs - electric - net	$	18,770	$	22,328		-15.9	%	$	32,631	$	23,233		40.5	%
Deferred energy costs - gas - net		3,554		1,353		162.7	%		1,609		6,084		-73.6	%
	$	22,324	$	23,681				$	34,240	$	29,317

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

Deferred energy costs - electric – net for the three months ended June 30, 2007 and 2006 reflect amortization of deferred energy costs of $11.7 million and $11.3 million, respectively; and an over-collection of amounts recoverable in rates of $7.1 million and $11.0 million, respectively. For the six months ended June 30, 2007 and 2006, amortization of deferred energy costs were $23.7 million and $22.6 million, respectively; with an over-collection of amounts recoverable in rates of $8.9 million and $0.6 million, respectively.

Deferred energy costs - gas - net for the three months ended June 30, 2007 and 2006 reflect amortization of deferred energy costs of $0.2 million and $1.1 million, respectively; and an over-collection of amounts recoverable in rates of $3.4 million and $0.2 million, respectively. For the six months ended June 30, 2007 and 2006, amortization of deferred energy costs were $0.6 million and $4.2 million, respectively; with an over-collection of amounts recoverable in rates of $1.0 million and $1.9 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

	Three Months							Six Months
	Ended June 30,							Ended June 30,
	2007		2006		Change from Prior Year %			2007		2006		Change from Prior Year %

Allowance for other funds
used during construction	$	3,365	$	1,449		132.2	%	$	6,834	$	2,152		217.6	%

Allowance for borrowed funds used during construction	$	2,671	$	1,307		104.4	%	$	5,455	$	1,937		181.6	%
	$	6,036	$	2,756		119.0	%	$	12,289	$	4,089		200.5	%

AFUDC increased for the three and six months ended June 30, 2007 compared to the same periods in 2006 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									Six Months
	Ended June 30,									Ended June 30,
	2007			2006			Change from Prior Year %			2007			2006			Change from Prior Year %

Other operating expense	$	35,994		$	33,119			8.7	%	$	68,842		$	67,294			2.3	%
Maintenance expense	$	10,314		$	8,995			14.7	%	$	16,595		$	16,768			-1.0	%
Depreciation and amortization	$	20,845		$	21,738			-4.1	%	$	41,317		$	44,962			-8.1	%
Interest charges on long-term debt	$	16,542		$	18,134			-8.8	%	$	32,650		$	35,824			-8.9	%
Interest charges-other	$	1,583		$	1,257			25.9	%	$	3,042		$	2,353			29.3	%
Interest accrued on deferred energy	$	(346	)	$	(1,512	)		-77.1	%	$	(1,111	)	$	(3,445	)		-67.8	%
Other income	$	(3,011	)	$	(2,662	)		13.1	%	$	(4,842	)	$	(4,810	)		0.7	%
Other expense	$	2,191		$	2,144			2.2	%	$	4,205		$	4,668			-9.9	%

Other operating expense increased for the three and six months ended June 30, 2007 compared to the same periods in 2006 primarily due to higher regulatory amortizations in 2007 and the settlement of contingency fees related to Enron in 2006, partially offset by increased capitalized labor costs in 2007.

Maintenance expense increased for the three month period ended June 30, 2007 compared to the same period in 2006 due to a planned outage at Tracy during the second quarter in 2007 (maintenance in 2006 occurred in the first quarter) and a major overhaul at Valmy in 2007.

Maintenance expense for the six month period ended June 30, 2007 is comparable to the same period in 2006.

Depreciation and amortization expenses decreased for the three and six months ended June 30, 2007 compared to the same periods in 2006 due to the change in depreciation rates as ordered by PUCN in SPPC’s General Electric and Gas Rate Cases in June 2006.

Interest charges on long-term debt decreased during for the three months and six months ended June 30, 2007, as compared to the same periods in 2006, due primarily to various re-financings of debt in 2006 at lower interest rates, redemption of debt and the refinancing of $80 million Water Facilities Refunding Revenue Bonds from fixed to variable rate in April 2007. These re-financings and redemptions were partially offset by the issuance of $300 million Series M notes in March 2006. See the 2006 Form 10-K, Note 6, Long-Term Debt of the Notes to Financial Statements for additional information regarding long-term debt and Note 4, Long-Term Debt of the Condensed Notes to Financial Statements

Interest charges-other increased during the three months and six months ended June 30, 2007, as compared to the same periods in 2006, due to higher amortization costs related to new debt issues and redemptions in 2006 and 2007.

Interest accrued on deferred energy costs decreased for the three months and six months ended June 30, 2007, due to lower deferred energy balances compared to the same period in 2006. See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income increased during the three months and six months ended June 30, 2007, as compared to the same periods in 2006, due to a refund of expenses, offset by the expiration of the amortization of gains associated with the disposition of property and lower interest income in 2007.

Other expense for the three months ended June 30, 2007 was comparable to the same period in 2006. Other expense decreased for the six months ended June 30, 2007, as compared to the same period in 2006 primarily due to a decrease in donations and payments made under the Supplemental Executive Retirement Plan.

ANALYSIS OF CASH FLOWS

Cash flows increased slightly during the six months ended June 30, 2007, when compared to the same period in 2006, due to increases in cash from operating and financing activities, offset by an increase in cash used in investing activities.

Cash flows from operating activities increased during the six months ended June 30, 2007, when compared to the same period in 2006, primarily due to increases in the BTER rate, which more accurately matches fuel and purchased power in 2007 and the net settlement with Enron in 2006.

Cash flows used by investing activities increased during the six months ended June 30, 2007, when compared to the same period in 2006, primarily due to construction costs associated with the expansion at the Tracy Generating Station.

Cash flows from financing activities increased during the six months ended June 30, 2007, compared to the same period in 2006, primarily due to a reduction in the redemption of debt and dividends paid to SPR.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows are electric and gas revenues, including the recovery of previously deferred energy and gas costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on SPPC’s outstanding indebtedness.

Available Liquidity as of June 30, 2007 (in millions)
Cash and Cash Equivalents	$	93.9
Balance available on Revolving Credit Facility (1)		331.0
	$	424.9

(1) As of August 6, 2007, SPPC had approximately $331 million available under its revolving credit facility. Additionally, if necessary, SPPC has the ability to issue additional debt, as discussed under Limitations on Indebtedness.

SPPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy. However, to fund capital requirements, as discussed in the 2006 Form 10-K, SPPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the six months ended June 30, 2007, there were no material changes to the contractual obligations described in SPPC’s 2006 Form 10-K except for certain financing transactions as discussed below.

Financing Transactions

6.75% General and Refunding Mortgage Notes, Series P

Tender Offer for General and Refunding Mortgage Bonds, Series A

Washoe County Water Facilities Refunding Revenue Bonds

The Water Bonds initial rates, as determined by auction on April 25, 2007, were 3.85%. The method of determining the interest rate on the Water Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.

The proceeds of the offerings were used to refund the $80 million aggregate principal amount of 5.00% Washoe County Water Facilities Revenue Bonds, Series 2001.

Factors Affecting Liquidity

Financial Covenants

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 that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2007, SPPC was in compliance with these covenants.

Limitations on Indebtedness

Certain factors impact SPPC’s ability to issue debt:

Financing Authority from the PUCN: On June 22, 2007, SPPC received PUCN authorization to enter into financings of $1.72 billion through the year 2009. Of this total, $300 million is contingent upon the PUCN’s approval of the Ely Energy Center in 2008. The remaining authority, $1.42 billion, includes authority for the revolving credit facility, authority to issue new debt and to refinance existing debt. As of June 30, 2007, SPPC used approximately $675 million of the $1.42 billion authority, as such approximately $745 million of the authority remains.

Limits on Bondable Property: 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 the General and Refunding Mortgage Indenture. As of June 30, 2007, SPPC has the capacity to issue $297 million of General and Refunding Mortgage Securities.

3. Financial Covenants in its financing agreements.

The terms of certain SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of SPPC’s Series H Notes and SPPC’s Amended and Restated Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless certain covenants are satisfied. See the 2006 Form 10-K, Note 8, Debt Covenant and Other Restrictions of the Notes to Financial Statements.

As of June 30, 2007, the financial covenants under the revolving credit facility, which are more restrictive than the Series H Notes restriction, would allow SPPC to issue up to $720.9 million of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, at $2.0 billion as of June 30, 2007. Therefore, SPPC would not be materially limited by SPR’s cap on additional indebtedness.

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 $2.0 billion, depending on the Utilities’ combined usage of their revolving credit facilities at the time of the covenant calculation.

Limitations on Ability to Issue General and Refunding Mortgage Bonds

SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of June 30, 2007, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (2) above under “Limitations on Indebtedness”, $297 million of additional securities may be issued under the General and Refunding Mortgage Indenture as of June 30, 2007. That amount has been determined on the basis of:

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

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.

Credit Ratings

SPPC is rated by four Nationally Recognized Statistical Rating Organizations: S&P, Moody’s, Fitch and DBRS. As of August 3, 2007 the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+

* Ratings are investment grade

In June 2007, Moody’s placed the senior secured debt at SPPC under review for possible upgrade, and S&P and Fitch revised their outlook on the company to Positive from Stable. In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to SPPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment grade. DBRS’s trend for the company is Stable.

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, 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. SPR does not expect that the new PUHCA law or the regulations promulgated by the FERC will have a material impact on the company and how its public utility subsidiaries are regulated.

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the California Public Utilities Commission (CPUC) with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit Integrated Resource Plans (IRPs) to the PUCN for approval.

Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies. The following regulatory proceedings have affected, or are expected to affect the utilities financial positions, results of operations and cash flows.

The Utilities were required to file annual Deferred Energy Accounting Adjustment (DEAA) cases, annual Base Tariff Energy Rate (BTER) Updates and biennial GRCs in Nevada. Upon the passage of legislation in 2007, the Utilities are required to file quarterly BTER Updates and triennial GRCs. A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER update is to set rates to recover current energy costs. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital. As of June 30, 2007, NPC’s and SPPC’s balance sheet included approximately $412.2 million and $28.2 million, respectively, of deferred energy costs of which $434.1 million and $29.2 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 Notes to Financial Statements.

Rate case applications filed in 2006 and 2007, as well as other regulatory matters such as, the Utilities’ IRP’s 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 the 2006 Form 10-K.

FERC Matters

FERC 890

On March 16, 2007, the FERC issued Order 890 (Order), which amends the FERC’s open transmission access rules adopted in Order Nos. 888 and 889 and revises the FERC’s pro forma Open Access Transmission Tariff (OATT). The OATT revisions went into effect on July 13, 2007. The Utilities made a filing with FERC on May 16, 2007, requesting modification of certain aspects of the OATT to ensure reservation of sufficient firm transmission import rights on their systems to comply with the Utilities’ PUCN-approved IRPs, which call for the use of short-term power purchases to meet summer and winter peak demands. The Utilities' proposed OATT revisions were accepted for filing by FERC and permitted to become effective on July 13, 2007, for a term of three years. Should the Utilities propose an extension beyond the three-year term, FERC stated that they will be required to demonstrate why the unique circumstances that FERC determined justified acceptance of the Utilities’ proposal have not improved.

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2007, 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
	2007			2008			2009			2010			2011			Thereafter			Total			Value
Long-term Debt
SPR
Fixed Rate	$	-		$	-		$	-		$	-		$	-		$	549,209		$	549,209		$	564,114
Average Interest Rate		-			-			-			-			-			7.75	%		7.75	%

NPC
Fixed Rate	$	9		$	12		$	-		$	-		$	364,000		$	1,916,579		$	2,280,600		$	2,318,924
Average Interest Rate		8.17	%		8.17	%		-			-			8.14	%		6.35	%		6.64	%
Variable Rate	$	-		$	-		$	15,000		$	125,000		$	-		$	192,500		$	332,500		$	332,500
Average Interest Rate		-			-			3.97	%		6.20	%		-			3.78	%		4.70	%

SPPC
Fixed Rate	$	1,053		$	101,643		$	600		$	-		$	-		$	725,000		$	828,296		$	832,204
Average Interest Rate		6.40	%		7.96	%		6.40	%		-			-			6.37	%		6.57	%
Variable Rate	$	-		$	-		$	-		$	-		$	-		$	348,250		$	348,250		$	348,250
Average Interest Rate		-			-			-			-			-			3.70	%		3.70	%

Total Debt	$	1,062		$	101,655		$	15,600		$	125,000		$	364,000		$	3,731,538		$	4,338,855		$	4,395,992

Commodity Price Risk

See the 2006 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, 2006.

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 $58.9 million as of June 30, 2007, which increased from the $31.1 million balance at December 31, 2006. The increase from December 31, 2006 is primarily due to a $25 million exposure associated with a 285 MW summer 2007 tolling agreement executed by NPC in January 2007.

ITEM 4. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

SPR, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of June 30, 2007, 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 2007 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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, 2006 and Quarterly Reports on Form 10-Q for the quarter ended March 31, 2007, 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, in the Condensed 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 13, Commitments and Contingencies of the Notes to Financial Statements. The Nevada Supreme Court has since rendered its decision in the appeal. 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. On May 10, 2007, Allegheny and Merrill Lynch filed renewed motions to dismiss 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. NPC opposed the motion to dismiss. On July 30, 2007 the Court denied the Motion and further set the case for trial in May 2008.

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 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. The Utilities have since negotiated bilateral settlement agreements with all power suppliers that had termination claims for undelivered power against the Utilities. The Utilities were unable to reach settlement with other respondents.

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 the July 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. On May 3, 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 decision. The Utilities, together with other parties and the Federal Energy Regulatory Commission, expect to file their opposition to these Petitions on August 6, 2007. The Utilities cannot predict whether the U.S. Supreme Court will grant or deny the Petition.

Environmental

Nevada Power Company

Reid Gardner Station

As disclosed in prior filings, in June 2006, the Environmental Protection Agency (EPA) issued a Finding and Notice of Violation (NOV) related to monitoring, recordkeeping and emission exceedances at the Reid Gardner facility. In April 2007, NPC lodged a Consent Decree in federal district court with the NDEP, EPA and the Department of Justice (DOJ) regarding the NOVs and providing for additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that will be required to resolve the alleged violations. Terms of the Consent Decree include a $1.1 million fine, funding of projects, of which NPC expects to spend approximately $2 million for the Supplemental Environmental Project with the Clark County School District, and the installation of emission reduction equipment at the facility. The environmental project is aimed at achieving increased energy efficiency and cost savings. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations, and which will satisfy the terms of the consent decree, were previously submitted by NPC to the PUCN in NPC’s 2006 IRP filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen. Capital expenditures are estimated at $84.2 million as approved by the PUCN; however, amounts may change depending on the procurement of material and services.

Clark Station

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 2006 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 Reports on Form 10-K for the year ended December 31, 2006 and Quarterly Reports on Form 10-Q for the quarter ended March 31, 2007, except as discussed below.

If Federal and/or State requirements are imposed on NPC and SPPC mandating further emission reductions, including limitations on carbon dioxide (CO2) emissions, such requirements could make some electric generating units, including the proposed Ely Energy Center, uneconomical to construct, maintain or operate.

Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. Certain Congressional leaders, environmental advocacy groups and regulatory agencies in the United States have also been focusing considerable attention on carbon dioxie (CO2) emissions from power generation facilities and their potential role in climate change. Particular attention has been focused on proposals for new coal-fired generation facilities, such as the Ely Energy Center. Although a number of bills have been introduced in Congress that would compel CO2 emission reductions, none has been enacted to date. Future changes in environmental laws or regulations governing emissions reductions could make certain electric generating units, especially those utilizing coal for fuel, uneconomical to construct, maintain or operate or could require design changes or the adoption of new technologies that could significantly increase costs or delay in-service dates. In addition, any legal obligation that would require the Utilities to substantially reduce its emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

If SPR is precluded from receiving dividends from the Utilities, its financial condition, and its ability to meet its debt service obligations, pay dividends and make capital contributions to its subsidiaries, will be materially adversely affected.

SPR is a holding company with no significant operations of its own. Its cash flows are substantially derived from dividends paid to it by the Utilities, which are typically utilized to service SPR’s debt and reinvested in SPR’s subsidiaries as contributions to capital. Subject to various factors to be considered periodically by SPR’s Board of Directors, a portion of SPR’s cash flow may be used to make dividend payments on its common stock.

The Utilities are subject to restrictions on their ability to pay dividends to SPR under the terms of certain of their respective financing agreements. In addition, certain provisions of the Federal Power Act could, depending on the interpretation thereof, limit or prohibit the payment of dividends to SPR.

Assuming that the Utilities meet the requirements to pay dividends under the Federal Power Act, under their material dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is an amount less than 50% of such Utility’s consolidated net income plus the amount of capital contributions made to such Utility by SPR for the period from the date of issuance of the respective series of debt securities to the end of the most recently ended fiscal quarter. If they do not meet these conditions, the Utilities can still pay SPR’s reasonable fees and expenses, provided that each such Utility has a cash flow to fixed charge coverage ratio of at least 1.75:1 over the prior four fiscal quarters. Due to the cumulative calculation of this restriction, NPC’s Series G Notes and SPPC’s Series H Notes are effectively the most restrictive dividend limitations. In addition, under the most restrictive of their dividend restrictions, each of the Utilities has a carve-out that permits them to pay up to $25 million to SPR from the date of issuance of the applicable debt securities, regardless of whether the other conditions to paying dividends have been met. Although each Utility currently meets the conditions described above, a significant loss by either Utility could cause that Utility to be precluded from paying dividends to SPR until such time as that Utility again meets the coverage test. In 2006, SPR received approximately $53.7 million in dividends from the Utilities to meet its debt service obligations. As of June 30, 2007, SPR received approximately $20.2 million in dividends from the Utilities to meet its debt service obligations.

We cannot assure investors that future dividend payments on our Common Stock will be made or, if made, in what amounts they may be paid.

On July 28, 2007, SPR’s Board of Director’s declared a quarterly cash dividend of $0.08 per share of Common Stock, payable on September 12, 2007 to shareholders of record on August 24, 2007. This dividend was the first declared by the Board since February 2002. Dividends are considered periodically by SPR’s Board of Directors and are subject to factors that ordinarily affect dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and dividend restrictions in SPR’s and the Utilities’ financing agreements. The Board will continue to review these factors on a periodic basis to determine if and when it would be prudent to declare a dividend on SPR’s Common Stock. There is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid in the same amount or with the same frequency as in the past.

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

The 2007 Annual Meeting of the Stockholders of Sierra Pacific Resources was held at 10:00 a.m., Pacific Daylight Time, on Monday May 7, 2007, at the Grand Sierra Resort and Casino, 2500 E. Second Street, Reno, Nevada.

Two proposals were presented for stockholder consideration: (1) election of four members of the Board of Directors to serve until the Annual Meeting in 2010, and until their successors are elected and qualified; and (2) to consider whether to adopt a shareholder proposal requesting Directors to take the steps necessary, in the most expeditious manner possible, to adopt annual election of each director.

Four Directors, Walter M. Higgins, Brian J. Kennedy, John F. O’Reilly, and Michael W. Yackira were elected to serve three year terms expiring at the 2010 Annual Meeting of Stockholders. Directors whose term expires in 2008: Joseph B. Anderson, Jr., Krestine M. Corbin, Philip G. Satre and Clyde T. Turner. Directors whose term expires in 2009: Mary Lee Coleman, T. J. Day, Jerry E. Herbst, and Donald D. Snyder.

The certified voting results are shown below:

Election of Directors For Withheld

Walter M. Higgins 185,801,635 3,657,750

Brian J. Kennedy 186,433,558 3,025,827

John F. O’Reilly 185,689,697 3,769,687

Michael W. Yackira 185,994,598 3,464,786

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 is required to approve the Shareholder proposal; accordingly, the proposal was not approved.

For Against Abstain

100,685,948 61,995,989 990,390

45.50% 28.02% 0.44%

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

(10)

Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company:

10.1 Summary of Compensation Arrangement with Walter M. Higgins.

(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 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.

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 6, 2007 By: /s/ William D. Rogers

William D. Rogers

Chief Financial Officer

(Principal Financial Officer)

Date: August 6, 2007 By: /s/ John E. Brown

John E. Brown

Controller

(Principal Accounting Officer)

Nevada Power Company

(Registrant)

Date: August 6, 2007 By: /s/ William D. Rogers

William D. Rogers

Chief Financial Officer

(Principal Financial Officer)

Date: August 6, 2007 By: /s/ John E. Brown

John E. Brown

Controller

(Principal Accounting Officer)

Sierra Pacific Power Company

(Registrant)

Date: August 6, 2007 By: /s/ William D. Rogers

William D. Rogers

Chief Financial Officer

(Principal Financial Officer)

Date: August 6, 2007 By: /s/ John E. Brown

John E. Brown

Controller

(Principal Accounting Officer)


	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


Sierra Pacific Resources:	Large accelerated filerþ	Accelerated filero	Non-accelerated filero
Nevada Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filerþ
Sierra Pacific Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filerþ


Class		Outstanding at August 2, 2007
Common Stock, $1.00 par value of Sierra Pacific Resources		221,625,616 Shares

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED June 30, 2007


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