UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

OR

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

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation
1-08788	SIERRA PACIFIC RESOURCES	88-0198358	Nevada
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011
2-28348	NEVADA POWER COMPANY	88-0420104	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 367-5000
0-00508	SIERRA PACIFIC POWER COMPANY	88-0044418	Nevada
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ (Response applicable to all registrants)

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

Class	Outstanding at October 31, 2007
Common Stock, $1.00 par value of Sierra Pacific Resources	221,647,972 Shares

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

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

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

1

SIERRA PACIFIC RESOURCES

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2007

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

ITEM 1.	Financial Statements
Sierra Pacific Resources -
	Consolidated Balance Sheets – September 30, 2007 and December 31, 2006…………...……...…………......................................	3
	Consolidated Income Statements – Three Months and Nine Months Ended September 30, 2007 and 2006...….................................	4
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2007 and 2006…..…………....................................	5
Nevada Power Company -
	Consolidated Balance Sheets – September 30, 2007 and December 31, 2006…………...…………..….........................................	6
	Consolidated Income Statements – Three Months and Nine Months Ended September 30, 2007 and 2006.….................................	7
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2007 and 2006….…………....................................	8
Sierra Pacific Power Company -
	Consolidated Balance Sheets – September 30, 2007 and December 31, 2006…………...…………..….........................................	9
	Consolidated Income Statements – Three Months and Nine Months Ended September 30, 2007 and 2006.…..................................	10
	Consolidated Statements of Cash Flows – Nine Months Ended September 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…………………........................................	27
	Sierra Pacific Resources………………………………………………….……………………………...................................	32
	Nevada Power Company…………………………………………………….…………………………….............................	35
	Sierra Pacific Power Company……………………………………………………………………………..............................	43
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk…………………………………………………....................................	53
ITEM 4.	Controls and Procedures…………………………………………………………………………………………............................	54
	PART II - OTHER INFORMATION
ITEM 1.	Legal Proceedings…………………………………………………………………………...…………….......................................	54
ITEM 1A.	Risk Factors……………………………………………………………………………………………………..............................	56
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds.............................................................................................................	56
ITEM 3.	Defaults Upon Senior Securities........................................................................................................................................................	56
ITEM 4.	Submission of Matters to a Vote of Security Holders…………………………………………………………..................................	56
ITEM 5.	Other Information…………………………………………………………………………………………......................................	56
ITEM 6.	Exhibits…………………………………………………….…………………………………………………................................	57
Signature Page and Certifications…..…………………………………………………………………………...…………..........................................		60

2

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		September 30, 2007		December 31,2006
ASSETS
Utility Plant at Original Cost:
Plant in service		$	8,336,827	$	7,954,337
Less accumulated provision for depreciation			2,458,329		2,333,357
			5,878,498		5,620,980
Construction work-in-progress			867,378		466,018
			6,745,876		6,086,998
Investments and other property, net			31,522		34,325
Current Assets:
Cash and cash equivalents			100,860		115,709
Accounts receivable less allowance for uncollectible accounts:
	2007-$39,483; 2006-$39,566		561,947		415,082
Deferred energy costs - electric (Note 1)			186,854		168,260
Materials, supplies and fuel, at average cost			117,345		103,757
Risk management assets (Note 5)			22,461		27,305
Deferred income taxes			34,316		55,546
Deposits and prepayments for energy			708		15,968
Other			44,856		31,580
			1,069,347		933,207
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			190,824		382,286
Regulatory tax asset			259,305		263,170
Regulatory asset for pension plans			209,426		223,218
Other regulatory assets			727,830		668,624
Risk management assets (Note 5)			32,560		7,586
Risk management regulatory assets - net (Note 5)			55,814		122,911
Unamortized debt issuance costs			67,698		67,106
Other			89,676		42,645
			1,633,133		1,777,546
TOTAL ASSETS		$	9,479,878	$	8,832,076
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	2,808,253	$	2,622,297
Long-term debt			4,337,745		4,001,542
			7,145,998		6,623,839
Current Liabilities:
Current maturities of long-term debt			109,614		8,348
Accounts payable			295,834		282,463
Accrued interest			72,655		56,426
Accrued salaries and benefits			35,719		33,146
Current income taxes payable			3,489		5,914
Risk management liabilities (Note 5)			85,756		123,065
Accrued taxes			7,638		6,290
Deferred energy costs - gas (Note 1)			4,484		-
Other current liabilities			64,693		60,422
			679,882		576,074
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			852,837		791,428
Deferred investment tax credit			32,685		35,218
Regulatory tax liability			31,672		34,075
Customer advances for construction			96,645		91,895
Accrued retirement benefits			134,129		226,420
Risk management liabilities (Note 5)			12,892		10,746
Regulatory liabilities			313,178		301,903
Other			179,960		140,478
			1,653,998		1,632,163
TOTAL CAPITALIZATION AND LIABILITIES		$	9,479,878	$	8,832,076
The accompanying notes are an integral part of the financial statements.

3

SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
OPERATING REVENUES:
Electric	$	1,185,205		$	1,060,574		$	2,676,713		$	2,468,512
Gas		20,839			21,106			137,337			141,128
Other		6			287			325			1,302
		1,206,050			1,081,967			2,814,375			2,610,942
OPERATING EXPENSES:
Operation:
Purchased power		410,467			396,133			851,396			906,578
Fuel for power generation		238,180			256,688			658,392			613,965
Gas purchased for resale		11,661			13,492			103,169			105,240
Deferral of energy costs - electric - net		66,660			17,700			193,954			74,721
Deferral of energy costs - gas - net		2,594			1,130			4,203			7,214
Reinstatement of deferred energy (Note 3)		-			(178,825	)		-			(178,825	)
Other		98,399			91,255			275,414			264,612
Maintenance		23,308			23,784			77,686			69,140
Depreciation and amortization		58,876			56,029			174,787			170,112
Taxes:
Income taxes		69,677			108,986			76,166			107,392
Other than income		13,091			11,802			37,710			36,740
		992,913			798,174			2,452,877			2,176,889
OPERATING INCOME		213,137			283,793			361,498			434,053
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		9,214			3,343			22,393			13,649
Interest accrued on deferred energy		4,633			6,219			13,020			22,573
Carrying charge for Lenzie		-			10,040			16,080			23,206
Reinstated interest on deferred energy (Note 3)		-			-			11,076			-
Other income		4,605			9,430			18,293			28,027
Other expense		(5,044	)		(4,534	)		(18,110	)		(13,968	)
Income taxes		(4,572	)		(8,262	)		(20,630	)		(25,205	)
		8,836			16,236			42,122			48,282
Total Income Before Interest Charges		221,973			300,029			403,620			482,335
INTEREST CHARGES:
Long-term debt		69,686			74,444			204,681			225,106
Other		7,626			6,199			23,625			16,433
Allowance for borrowed funds used during construction		(7,561	)		(2,860	)		(18,269	)		(12,869	)
		69,751			77,783			210,037			228,670
Preferred stock dividend requirements of subsidiary and premium on redemption		-			-			-			2,341
NET INCOME APPLICABLE TO COMMON STOCK	$	152,222		$	222,246		$	193,583		$	251,324
Amount per share basic and diluted - (Note 7)
Net Income applicable to common stock	$	0.69		$	1.05		$	0.87		$	1.23
Weighted Average Shares of Common Stock Outstanding - basic		221,612,243			211,143,616			221,424,682			204,303,110
Weighted Average Shares of Common Stock Outstanding - diluted		221,968,802			211,641,821			221,783,424			204,744,823
The accompanying notes are an integral part of the financial statements.

4

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income applicable to common stock	$	193,583		$	251,324
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		174,787			170,113
Deferred taxes and deferred investment tax credit		103,598			122,062
AFUDC		(22,393	)		(26,518	)
Amortization of deferred energy costs - electric		172,046			130,279
Amortization of deferred energy costs - gas		734			4,773
Deferral of energy costs - electric		11,900			(77,908	)
Deferral of energy costs - gas		3,749			1,897
Deferral of energy costs - terminated suppliers		-			2,309
Reinstatement of deferred energy		-			(178,825	)
Carrying charge on Lenzie plant		(16,080	)		(26,957	)
Reinstated interest on deferred energy		(11,076	)		-
Other, net		11,422			(24,985	)
Changes in certain assets and liabilities:
Accounts receivable		(146,865	)		(127,424	)
Materials, supplies and fuel		(13,588	)		(10,651	)
Other current assets		1,982			36,397
Accounts payable		37,232			(17,129	)
Payment to terminating supplier		-			(65,368	)
Proceeds from claim on terminating supplier		-			41,365
Accrued retirement benefits		(92,291	)		4,807
Other current liabilities		24,422			33,085
Risk Management assets and liabilities		11,805			(2,654	)
Other assets		7,964			10,526
Other liabilities		(9,872	)		(9,810	)
Net Cash from Operating Activities		443,059			240,708
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(921,998	)		(769,080	)
AFUDC		22,393			26,518
Customer advances for construction		4,749			19,402
Contributions in aid of construction		41,243			28,874
Investments and other property - net		2,928			13,559
Net Cash used by Investing Activities		(850,685	)		(680,727	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			3,612
Proceeds from issuance of long-term debt		1,201,354			2,181,753
Retirement of long-term debt		(800,471	)		(1,894,875	)
Redemption of preferred stock		-			(51,366	)
Proceeds from exercise of stock options		5,112			1,040
Sale of common stock, net of issuance cost		4,525			280,499
Dividends paid		(17,743	)		(1,944	)
Net Cash from Financing Activities		392,777			518,719
Net Increase (Decrease) in Cash and Cash Equivalents		(14,849	)		78,700
Beginning Balance in Cash and Cash Equivalents		115,709			172,735
Ending Balance in Cash and Cash Equivalents	$	100,860		$	251,435
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	193,549		$	227,418
Income taxes	$	9,727		$	4,726
The accompanying notes are an integral part of the financial statements

5

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		September 30,		December 31,
		2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service		$	5,486,226	$	5,187,665
Less accumulated provision for depreciation			1,359,402		1,276,192
			4,126,824		3,911,473
Construction work-in-progress			434,595		238,518
			4,561,419		4,149,991
Investments and other property, net			19,403		22,176
Current Assets:
Cash and cash equivalents			44,888		36,633
Accounts receivable less allowance for uncollectible accounts:
$	2007-33,460; 2006-$32,834		425,028		244,623
Deferred energy costs - electric (Note 1)			170,813		129,304
Materials, supplies and fuel, at average cost			67,943		60,754
Risk management assets (Note 5)			14,443		16,378
Deferred income taxes			92,246		72,294
Deposits and prepayments for energy			280		7,056
Other			31,357		19,901
			846,998		586,943
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			190,824		359,589
Regulatory tax asset			155,009		153,471
Regulatory asset for pension plans			108,672		113,646
Other regulatory assets (Note 1)			499,241		440,369
Risk management assets			29,190		5,379
Risk management regulatory assets - net (Note 5)			32,889		83,886
Unamortized debt issuance costs			37,711		38,856
Other			69,336		33,209
			1,122,872		1,228,405
TOTAL ASSETS		$	6,550,692	$	5,987,515
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,323,684	$	2,172,198
Long-term debt			2,677,193		2,380,139
			5,000,877		4,552,337
Current Liabilities:
Current maturities of long-term debt			7,971		5,948
Accounts payable			178,194		148,003
Accounts payable, affiliated companies			37,831		20,656
Accrued interest			49,667		37,010
Dividends declared			-		13,472
Accrued salaries and benefits			17,848		14,989
Current income taxes payable			3,489		3,981
Intercompany income taxes payable			100,170		884
Risk management liabilities (Note 5)			59,887		84,674
Accrued taxes			3,809		2,671
Other current liabilities			49,941		48,298
			508,807		380,586
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			594,039		599,747
Deferred investment tax credit			14,076		15,213
Regulatory tax liability			12,482		13,451
Customer advances for construction			61,468		60,040
Accrued retirement benefits			40,680		90,474
Risk management liabilities (Note 5)			8,217		7,061
Regulatory liabilities			179,355		171,298
Other			130,691		97,308
			1,041,008		1,054,592
TOTAL CAPITALIZATION AND LIABILITIES		$	6,550,692	$	5,987,515
The accompanying notes are an integral part of the financial statements.

6

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
OPERATING REVENUES:
Electric	$	894,226		$	776,235		$	1,887,499		$	1,701,379
OPERATING EXPENSES:
Operation:
Purchased power		313,487			289,975			584,797			638,664
Fuel for power generation		166,284			183,622			471,142			425,138
Deferral of energy costs-net		54,868			19,960			149,531			53,748
Reinstatement of deferred energy (Note 3)		-			(178,825	)		-			(178,825	)
Other		61,400			54,927			167,401			156,765
Maintenance		16,360			15,719			54,143			44,307
Depreciation and amortization		38,151			34,955			112,745			104,076
Taxes:
Income taxes		65,407			103,853			65,849			103,617
Other than income		8,005			7,129			22,431			21,287
		723,962			531,315			1,628,039			1,368,777
OPERATING INCOME		170,264			244,920			259,460			332,602
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		4,701			1,986			11,046			10,140
Interest accrued on deferred energy		4,573			4,786			11,849			17,695
Carrying charge for Lenzie		-			10,040			16,080			23,206
Reinstated interest on deferred energy (Note 3)		-			-			11,076			-
Other income		2,315			4,080			10,345			12,831
Other expense		(1,346	)		(2,050	)		(8,772	)		(6,353	)
Income taxes		(3,518	)		(6,735	)		(17,649	)		(19,785	)
		6,725			12,107			33,975			37,734
Total Income Before Interest Charges		176,989			257,027			293,435			370,336
INTEREST CHARGES:
Long-term debt		41,955			43,355			123,029			132,285
Other		5,876			4,537			18,315			11,828
Allowance for borrowed funds used during construction		(3,936	)		(1,978	)		(9,189	)		(10,050	)
		43,895			45,914			132,155			134,063
NET INCOME	$	133,094		$	211,113		$	161,280		$	236,273
The accompanying notes are an integral part of the financial statements.

7

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	161,280		$	236,273
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		112,745			104,076
Deferred taxes and deferred investment tax credit		76,188			113,015
AFUDC		(11,046	)		(20,190	)
Amortization of deferred energy costs		137,633			95,830
Deferral of energy costs		700			(59,765	)
Deferral of energy costs - terminated suppliers		-			1,607
Reinstatement of deferred energy		-			(178,825	)
Carrying charge on Lenzie plant		(16,080	)		(26,957	)
Reinstated interest on deferred energy		(11,076	)		-
Other, net		(8,461	)		(26,129	)
Changes in certain assets and liabilities:
Accounts receivable		(180,404	)		(159,526	)
Materials, supplies and fuel		(7,189	)		(11,336	)
Other current assets		(4,680	)		12,868
Accounts payable		60,407			(13,302	)
Payment to terminating supplier		-			(37,410	)
Proceeds from claim on terminating supplier		-			26,391
Accrued retirement benefits		(49,794	)		78
Other current liabilities		18,298			20,152
Risk Management assets and liabilities		5,490			(1,161	)
Other assets		6,495			10,205
Other liabilities		8,101			(8,055	)
Net Cash from Operating Activities		298,607			77,839
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(584,967	)		(555,786	)
AFUDC		11,046			20,190
Customer advances for construction		1,428			13,913
Contributions in aid of construction		26,240			19,673
Investments and other property - net		2,899			6,351
Net Cash used by Investing Activities		(543,354	)		(495,659	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		699,254			1,689,134
Retirement of long-term debt		(422,780	)		(1,491,958	)
Additional investment by parent company		-			200,000
Dividends paid		(23,472	)		(31,968	)
Net Cash from Financing Activities		253,002			365,208
Net Increase (Decrease) in Cash and Cash Equivalents		8,255			(52,612	)
Beginning Balance in Cash and Cash Equivalents		36,633			98,681
Ending Balance in Cash and Cash Equivalents	$	44,888		$	46,069
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	115,047		$	136,072
Income taxes	$	6,760		$	4,714
The accompanying notes are an integral part of the financial statements

8

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	September 30,		December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,850,601	$	2,766,672
Less accumulated provision for depreciation		1,098,928		1,057,165
		1,751,673		1,709,507
Construction work-in-progress		432,783		227,500
		2,184,456		1,937,007
Investments and other property, net		584		609
Current Assets:
Cash and cash equivalents		28,574		53,260
Accounts receivable less allowance for uncollectible accounts:
2007-$6,023 :2006 - $6,732		136,850		170,106
Deferred energy costs - electric (Note 1)		16,041		38,956
Materials, supplies and fuel, at average cost		49,389		42,990
Risk management assets (Note 5)		8,018		10,927
Deferred income taxes		403		-
Deposits and prepayments for energy		428		8,912
Other		13,154		11,184
		252,857		336,335
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		-		22,697
Regulatory tax asset		104,296		109,699
Regulatory asset for pension plans		98,090		106,666
Other regulatory assets		228,589		228,255
Risk management assets (Note 5)		3,370		2,207
Risk management regulatory assets - net (Note 5)		22,925		39,025
Unamortized debt issuance costs		20,654		17,981
Other		18,389		7,356
		496,313		533,886
TOTAL ASSETS	$	2,934,210	$	2,807,837
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	937,546	$	884,737
Long-term debt		1,110,166		1,070,858
		2,047,712		1,955,595
Current Liabilities:
Current maturities of long-term debt		101,643		2,400
Accounts payable		74,627		89,743
Accounts payable, affiliated companies		19,375		11,769
Accrued interest		18,514		7,200
Dividends declared		-		6,736
Accrued salaries and benefits		14,946		15,209
Intercompany income taxes payable		5,530		9,055
Deferred income taxes		-		8,881
Risk management liabilities (Note 5)		25,869		38,391
Accrued taxes		3,669		3,407
Deferred energy costs - gas (Note 1)		4,484		-
Other current liabilities		14,752		12,125
		283,409		204,916
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		258,721		278,515
Deferred investment tax credit		18,609		20,005
Regulatory tax liability		19,190		20,624
Customer advances for construction		35,176		31,855
Accrued retirement benefits		88,115		124,254
Risk management liabilities (Note 5)		4,675		3,685
Regulatory liabilities		133,823		130,605
Other		44,780		37,783
		603,089		647,326
TOTAL CAPITALIZATION AND LIABILITIES	$	2,934,210	$	2,807,837
The accompanying notes are an integral part of the financial statements.

9

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
OPERATING REVENUES:
Electric	$	290,979		$	284,339		$	789,214		$	767,133
Gas		20,839			21,106			137,337			141,128
		311,818			305,445			926,551			908,261
OPERATING EXPENSES:
Operation:
Purchased power		96,980			106,158			266,599			267,914
Fuel for power generation		71,896			73,066			187,250			188,827
Gas purchased for resale		11,661			13,492			103,169			105,240
Deferral of energy costs - electric - net		11,792			(2,260	)		44,423			20,973
Deferral of energy costs - gas - net		2,594			1,130			4,203			7,214
Other		36,228			34,119			105,070			101,413
Maintenance		6,948			8,065			23,543			24,833
Depreciation and amortization		20,726			21,075			62,043			66,037
Taxes:
Income taxes		9,825			9,435			20,871			19,162
Other than income		5,050			4,622			15,138			15,311
		273,700			268,902			832,309			816,924
OPERATING INCOME		38,118			36,543			94,242			91,337
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		4,513			1,357			11,347			3,509
Interest accrued on deferred energy		60			1,433			1,171			4,878
Other income		1,865			2,491			6,707			7,301
Other expense		(2,938	)		(2,138	)		(7,143	)		(6,806	)
Income taxes		(1,104	)		(1,065	)		(3,597	)		(3,087	)
		2,396			2,078			8,485			5,795
Total Income Before Interest Charges		40,514			38,621			102,727			97,132
INTEREST CHARGES:
Long-term debt		17,096			18,134			49,746			53,958
Other		1,491			1,341			4,533			3,694
Allowance for borrowed funds used during construction		(3,625	)		(882	)		(9,080	)		(2,819	)
		14,962			18,593			45,199			54,833
NET INCOME		25,552			20,028			57,528			42,299
Preferred stock dividend requirements of subsidiary and premium on redemption		-			-			-			2,341
EARNINGS APPLICABLE TO COMMON STOCK	$	25,552		$	20,028		$	57,528		$	39,958
The accompanying notes are an integral part of the financial statements.

10

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	57,528		$	42,299
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		62,043			66,037
Deferred taxes and deferred investment tax credit		(25,456	)		(27,392	)
AFUDC		(11,347	)		(6,328	)
Amortization of deferred energy costs - electric		34,413			34,449
Amortization of deferred energy costs - gas		734			4,773
Deferral of energy costs - electric		11,200			(18,143	)
Deferral of energy costs - gas		3,749			1,897
Deferral of energy costs - terminated suppliers		-			702
Other, net		18,583			2,470
Changes in certain assets and liabilities:
Accounts receivable		33,257			64,902
Materials, supplies and fuel		(6,399	)		695
Other current assets		6,512			22,832
Accounts payable		3,310			12,914
Payment to terminating supplier		-			(27,958	)
Proceeds from claim on terminating supplier		-			14,974
Accrued retirement benefits		(36,139	)		4,938
Other current liabilities		13,940			22,004
Risk Management assets and liabilities		6,315			(1,493	)
Other assets		1,468			321
Other liabilities		(3,896	)		(1,630	)
Net Cash from Operating Activities		169,815			213,263
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(337,031	)		(213,294	)
AFUDC		11,347			6,328
Customer advances for construction		3,321			5,489
Contributions in aid of construction		15,004			9,201
Investments and other property - net		25			40
Net Cash used by Investing Activities		(307,334	)		(192,236	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			3,612
Proceeds from issuance of long-term debt		502,100			492,619
Retirement of long-term debt		(377,531	)		(402,671	)
Redemption of preferred stock		-			(51,366	)
Dividends paid		(11,736	)		(17,926	)
Net Cash from Financing Activities		112,833			24,268
Net Increase (Decrease) in Cash and Cash Equivalents		(24,686	)		45,295
Beginning Balance in Cash and Cash Equivalents		53,260			38,153
Ending Balance in Cash and Cash Equivalents	$	28,574		$	83,448
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	38,854		$	42,358
Income taxes	$	64		$	12
Noncash Activities:
Transfer of Regulatory Asset	$	-		$	18,888
The accompanying notes are an integral part of the financial statements

11

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 nine months ended September 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.

Through June 30, 2007, NPC had accumulated approximately $57.6 million in carrying charges; however, $8.1 million of this amount was not recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through rates.  For the nine month period ending September 30, 2007, NPC recognized $16.1 million in income.  NPC did not record a separate carrying charge component related to Lenzie for the three months ended September 30, 2007, as the plant is in rate base effective June 1, as discussed below.

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.

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

	September 30, 2007
	NPC			SPPC			SPPC			SPR
Description	Electric			Electric			Gas			Total
Unamortized balances approved for collection in current rates
Reinstatement of Deferred Energy       (effective 6/07, 10 years) (1)	$	182,477		$	-		$	-		$	182,477
Electric – NPC Period 5                     (effective 8/06, 2 years)		75,546			-			-			75,546
Electric – SPPC Period 5                   (effective 7/06, 2 years)		-			10,075			-			10,075
Electric – NPC Period 6                     (effective 6/07, 14 months)		35,334			-			-			35,334
Electric – SPPC Period 6                   (effective 7/07, 1 year)		-			11,566			-			11,566
Nat Gas – P6, LPG – P5                   (effective 12/06, 1 year)		-			-			190			190
Western Energy Crisis Rate Case (2)  (effective 6/07, 3 years)		69,381			-			-			69,381
Balances pending PUCN approval		-			-			860			860
Cumulative CPUC balance		-			5,352			-			5,352
Balances accrued since end of periods submitted for PUCN approval (3)		(1,101	)		(25,123	)		(5,534	)		(31,758	)
Western Energy Crisis Rate Case (2)		-			14,171			-			14,171
Total	$	361,637		$	16,041		$	(4,484	)	$	373,194
Current Assets
Deferred energy costs – electric	$	170,813		$	16,041			-		$	186,854
Deferred Assets
Deferred energy costs - electric	$	190,824			-			-		$	190,824
Current Liabilities
Deferred energy costs - gas		-			-		$	(4,484	)	$	(4,484	)
Total	$	361,637		$	16,041		$	(4,484	)	$	373,194

(1)  Reinstatement of Deferred Energy is discussed in Note 3, Regulatory Actions, of the Condensed Notes to Consolidated Financial Statements.

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

(3)   Credit balances repreeent potential refunds to the Utilities' customers.

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 September 30, 2007 is $15.5 million, of which $2.3 million would affect the effective tax rate if recognized.  The amount of unrecognized tax benefits decreased from the second quarter by a total of $723 thousand.  No interest or penalties have been accrued as of September 30, 2007.  No significant increases or decreases to unrecognized tax benefits are expected within the next 12 months.

13

SFAS 157

In September 2006, the 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, but does not expect the adoption of SFAS 157 to have a material impact on the consolidated financial statements of SPR and the Utilities.

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 on their consolidated financial statements.

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 cash collateral paid or 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 potential impact of the adoption of FIN 39-1 on their consolidated financial statements.

NOTE 2.                      SEGMENT INFORMATION

SPR has three reportable 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 other miscellaneous operating activities.

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		SPPC		SPR		SPR
September 30, 2007	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	894,226	$	290,979	$	1,185,205	$	20,839	$	6	$	1,206,050
Operating Income	$	170,264	$	37,893	$	208,157	$	225	$	4,755	$	213,137
Three Months Ended	NPC		SPPC		Total		SPPC		SPR		SPR
September 30, 2006	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	776,235	$	284,339	$	1,060,574	$	21,106	$	287	$	1,081,967
Operating Income	$	244,920	$	36,056	$	280,976	$	487	$	2,330	$	283,793
Nine Months Ended	NPC		SPPC		Total		SPPC		SPR		SPR
September 30, 2007	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	1,887,499	$	789,214	$	2,676,713	$	137,337	$	325	$	2,814,375
Operating Income	$	259,460	$	87,411	$	346,871	$	6,831	$	7,796	$	361,498
Nine Months Ended	NPC		SPPC		Total		SPPC		SPR		SPR
September 30, 2006	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	1,701,379	$	767,133	$	2,468,512	$	141,128	$	1,302	$	2,610,942
Operating Income	$	332,602	$	84,866	$	417,468	$	6,471	$	10,114	$	434,053

14

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 an additional $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.  Hearings on this matter were held in early October 2007 and a decision is expected by the end of November 2007.

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.

Hearings on these matters are scheduled to be held early November 2007.

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 requested to increase rates by $13.4 million, while recovering approximately $900 thousand of deferred gas costs.  This application requested an overall rate increase of 7.05%.  Hearings on these matters were held in the end of October 2007 and a decision is expected before December 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 million 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 were held in early October 2007 and a decision is expected during the fourth quarter of 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.  The PUCN decision was appealed by SPPC, and the case was ultimately remanded 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 was held in August 2007 in which the PUCN determined the scope of the proceedings and set a procedural schedule.  Hearings are expected to be held in early January 2008.

15

Approved Rate Cases

Nevada Power Company

NPC 2007 Quarterly BTER Filing

 In August 2007, NPC filed an application to update the going forward BTER.  NPC requested to increase rates by $22.7 million, resulting in a 1% increase.  The PUCN approved the requested rate change with rates effective October 1, 2007.

    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%, respectively, 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;  and

·   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

InJanuary 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 pursuant to which 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.

16

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  2007 Quarterly BTER Filing

 In August 2007, SPPC filed an application to update the going forward BTER.  SPPC requested to decrease rates by $17.4 million, resulting in a 1.85% decrease.  The PUCN approved the requested rate change with rates effective October 1, 2007.

    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 September 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 (dollars in thousands):

	NPC			SPPC		SPR Holding Co. and Other Subs.		SPR Consolidated
2007	$	-		$	534	$	-	$	534
2008		6,363			101,643		-		108,006
2009		22,128			600		-		22,728
2010		157,908			25,000		-		182,908
2011		369,821			-		-		369,821
		556,220			127,777		-		683,997
Thereafter		2,141,845			1,073,250		549,209		3,764,304
		2,698,065			1,201,027		549,209		4,448,301
Unamortized Premium(Discount) Amount		(12,901	)		10,782		1,177		(942	)
Total	$	2,685,164		$	1,211,809	$	550,386	$	4,447,359

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.

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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 (SEC).  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 SEC.  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 September 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 September 30, 2007.  NPC expects to transfer operations to the facilities in or around mid summer 2008.  In addition, NPC is preparing to sublease portions of the building.

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

Remainder of 2007	$	60
2008	$	1,489
2009	$	1,463
2010	$	1,535
2011	$	1,551
Thereafter	$	31,941
Total Minimum Lease Payments	$	38,039
Less amounts representing interest	$	22,195
Present Value of Net minimum lease payments	$	15,844

Minimum lease payments (operating lease portion) for the Southern Ops lease as of September 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 accrual 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.

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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 unrealized gains and losses on the Consolidated Statements of Income (dollars in millions):

	September 30, 2007										December 31, 2006
	Fair Value										Fair Value
		SPR			NPC			SPPC			SPR			NPC			SPPC
Risk management assets - current		$	22.4		$	14.4		$	8.0		$	27.3		$	16.4		$	10.9
Risk management assets – non-current			32.6			29.2			3.4			7.6			5.4			2.2
Total risk management assets			55.0			43.6			11.4			34.9			21.8			13.1
Risk management liabilities- current			85.8			59.9			25.9			123.1			84.7			38.4
Risk management liabilities - non-current			12.9			8.2			4.7			10.8			7.1			3.7
Total risk management liabilities			98.7			68.1			30.6			133.9			91.8			42.1
Less prepaid electric and gas options (at cost)			12.1			8.4			3.7			23.9			13.9			10.1
Total Risk Management Regulatory (Asset)/Liability - net (1)		$	(55.8	)	$	(32.9	)	$	(22.9	)	$	(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 September 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 September 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.

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Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $39.1 million.  Expenditures for 2007 through 2010 are projected to be approximately $8.8 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 for the school district.  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

As disclosed in prior filings, in May 2006, the EPA, by letter from the DOJ, notified NPC that it intended 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 at Clark Station.  NPC then entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations and in August 2007, a final Consent Decree between NPC and the EPA was entered with the 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, alleging, among other things, a declaration that the participants are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Peabody and others, including Southern California Edison (SCE) and Salt River, in June 1999 in the United States District Court for the District of Columbia (DC Lawsuit). 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.

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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.  Discovery is ongoing.  On October 4, 2007, Joint Owners filed a motion for partial summary judgment against Peabody’s claims for reimbursement of attorney fees and indemnification of liability in the event Peabody is held liable in the DC Lawsuit.  The court has yet to rule on the partial summary judgment motion.  The case is set for trial in December, 2008.  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 Coal Supply Agreement (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, Salt River and the Joint Owners filed a complaint in the Maricopa County (Arizona) Supreme Court seeking determinations that they are not liable for RHCC or FRC or, alternatively, that Peabody cannot recover RHCC and FRC until after the CSA ends.  The case was dormant for several years, while Peabody pursued other RHCC and FRC claims arising out of similar coal contracts.  The RHCC matter is in the early stages of litigation.  The FRC claim went to arbitration and parties are in the early process of selecting a panel.  Settlement discussions, led by Salt River, are continuous and ongoing.  NPC is briefed periodically by Salt River as settlement discussions advance.  NPC cannot predict the final outcome of the settlement but has recorded a $12.8 million liability, which management has assessed as the approximate amount to be paid, and a corresponding deferred debit for such claims, as management believes NPC will recover these costs through deferred energy.

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 Court denied the motions and asked parties to brief the Court on certain insurance coverage issues involving timing and cost recovery associated with rebuilding the dam.  A trial date has not been set.  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.

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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 net of 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 $22.9 million as of September 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 $4.7 million as of September 30, 2007.

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

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

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

		Three months ended September 30,				Nine months ended September 30,
		2007		2006		2007		2006
Basic EPS
Numerator ($000)
	Net income applicable to common stock	$	152,222	$	222,246	$	193,583	$	251,324
Denominator
	Weighted average number of common shares outstanding		221,612,243		211,143,616		221,424,682		204,303,110
Per Share Amounts
	Net income applicable to common stock	$	0.69	$	1.05	$	0.87	$	1.23
Diluted EPS
Numerator ($000)
	Net income applicable to common stock	$	152,222	$	222,246	$	193,583	$	251,324
Denominator (1)
	Weighted average number of shares outstanding before dilution		221,612,243		211,143,616		221,424,682		204,303,110
	Stock options		73,834		86,145		124,013		78,774
	Executive long term incentive plan - restricted		-		125,432		-		114,189
	Non-Employee Director stock plan		48,513		32,576		44,597		28,798
	Employee stock purchase plan		-		3,604		2,630		3,016
	Performance Shares		234,212		250,448		187,502		216,936
			221,968,802		211,641,821		221,783,424		204,744,823
Per Share Amounts
	Net income applicable to common stock	$	0.69	$	1.05	$	0.87	$	1.23

(1)   The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan for the three and nine months ended September 30, 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 nine months ended September 30, 2007, 685,582 and 713,826 shares, respectively, would be included and 953,995 and 940,287 shares, respectively, would be included for the three and nine months ended September 30, 2006.

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NOTE 8.                      PENSION AND OTHER POST-RETIREMENT BENEFITS

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

	For the Three Months Ended September 30,
	Pension Benefits		Other Postretirement Benefits
	2007	2006	2007	2006
Service cost	$          5,725	$          5,758	$             268	$             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
Net periodic benefit cost	$          7,316	$          7,651	$          2,616	$          3,733
	For the Nine Months Ended September 30,
	Pension Benefits		Other Postretirement Benefits
	2007	2006	2007	2006
Service cost	$        17,175	$        17,275	$          1,804	$          2,710
Interest cost	29,565	27,470	7,711	7,887
Expected return on plan assets	(31,422)	(30,547)	(3,927)	(3,773)
Amortization of prior service cost	1,222	1,419	91	94
Amortization of Transition Obligation	-	-	2,444	743
Amortization of net (gain)/loss	5,409	7,334	727	3,539
Net periodic benefit cost	$        21,949	$        22,951	$          8,850	$        11,200

In the third quarter ended September 30, SPR and the Utilities made contributions to the pension plan and the other postretirement benefits plan in the amount of $54 million and $46 million, respectively.  Due to SPR’s and the Utilities’ improved financial condition, management believed a higher contribution than previously estimated to be more appropriate.  At the present time, there is not expected to be any further contributions to either plan 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 September 30, 2007, NPC had paid $23.5 million in dividends to SPR and SPPC had paid $11.7 million in dividends to SPR in 2007.

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 September 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, their financing agreements do not currently significantly restrict SPR’s and the Utilities’ ability to pay dividends.

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NOTE 10.  DIVIDENDS

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

On November 1, 2007, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share payable on December 12, 2007, to common shareholders of record on November 19, 2007.

As of September 30, 2007, NPC and SPPC have paid $23.5 million and $11.7 million, respectively in dividends to SPR in 2007.  On November 1, 2007, NPC and SPPC declared a dividend to SPR of $10.7 million and $7.8 million, respectively.

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ITEM 2.          MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

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

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

(1)   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;

(2)   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;

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

(4)   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;

(5)   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;

(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;

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(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.

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EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of Sierra Pacific Resources (SPR) and its two primary subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC), collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to SPR 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 operates three reportable 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 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.

SPR recognized net income applicable to common stock of $152.2 million and $193.6 million for the three and nine months ended September 30, 2007 respectively, compared to $222.2 million and $251.3 million for the same respective periods in 2006.  Earnings decreased primarily as a result of the reinstatement of deferred energy in 2006 of approximately $116.2 million net of taxes recorded.  Partially offsetting this was:

·   an increase to operating income as a result of increased rates

·   settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case

·   an increase in AFUDC and allowance for borrowed funds used during construction due to the construction of  NPC’s Clark Peaking Units and SPPC’s Tracy Generating Station and;

·   a decrease in interest charges.

On November 1, SPR declared a dividend of $0.08 per share for shareholders of record on November 19, 2007.  The dividend will be paid on December 12.  The amount payable will be approximately $17.7 million.

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.  SPPC's gas business typically peaks in the winter.

For the three and nine months ended September 30, 2007, NPC’s revenues increased compared to the same periods in 2006 primarily due to higher rates, customer growth and hotter weather.  NPC’s rates increased primarily due to NPC’s General Rate Case (GRC), effective June 1, 2007 and various Base Tariff Energy Rate (BTER) and Deferred Energy Cases.  NPC’s net income for the three months ended and nine months ended September 30, 2007 decreased compared to the same periods in 2006 primarily due to the reinstatement of deferred energy of approximately $116.2 million net of taxes recorded in 2006.  Partially offsetting this was an increase in operating income as a result of increased rates and settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case.  See Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements and the 2006 Form 10-K for further discussion or regulatory matters.

For the three and nine months ended September 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 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 three months and nine months ending September 30, 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.

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Business Issues

SPR’s and the Utilities’ strategies are aimed at owning more generating facilities, reducing dependence on purchased power and diversifying fuel mix including the use of renewable energy and energy efficiency and conservation programs, while the Utilities’ service areas continue to grow.  Population growth forecasts, however, may be influenced by economic trends in hotel room expansion and changes in the local housing markets.  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 leveled out after the surge earlier this decade, the slower pace of housing starts has been partly offset by new casino projects in Las Vegas.  To meet the Utilities' obligations to serve their customers, the Utilities will continue to be subject to purchased power and natural gas markets that have been volatile in recent years.

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, strengthening our balance sheet and further improving liquidity continues to be, a significant business focus for 2007 and beyond.

Summarized below are significant business issues and challenges ahead in 2007 and beyond.  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) focus 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 that consists of two 750 MW coal generation units to be located near Ely, Nevada. In addition to the generation units, the PUCN approved the development and construction of a 250-mile 500 kilovolt (kV) transmission line that would deliver electricity from the Ely Energy Center and from any possible future renewable resource projects in the area, as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state.  The PUCN approved spending up to $300 million for development activities associated with the Ely Energy Center and transmission line; however, the PUCN placed a $155 million spending limit until the appropriate permits, as discussed below, are obtained.  For planning purposes, it is currently assumed that the capacity of the project, as well as the development and construction costs, would be shared by NPC and SPPC on an 80% - 20% basis, respectively.  The PUCN established the project as a “critical facility,” thereby allowing it to qualify for incentives that will be determined in a later filing.  NPC and SPPC are required to file amendments to their IRPs once elements of the plan, including final costs and timing of completion, can be more accurately estimated.  The Utilities expect to file an amendment to their IRP no later than Spring 2008.  As currently 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, negotiation of certain contracts, the potential initiation of any litigation challenging the project, and the timing and terms of permitting, among other factors, actual costs, scope, and timing of the completion of the project could differ materially from initial estimates.

In addition to PUCN approval and other factors, the timing and construction of the Ely Energy Center and transmission line are dependent on obtaining land use permits from the Bureau of Land Management and air permits from the Nevada Division of Environmental Protection (NDEP).  On October 31, 2007, the NDEP published a notice of intent to issue a Class I air quality permit, together with a draft operating permit, with respect to the Ely Energy Center.  The draft operating permit is subject to public comment, and a public hearing on the permit has been scheduled for January 9, 2008.  Possible changes to state and federal environmental laws or regulations, including those relating to carbon emissions from coal-fired power plants, could impact either permitting process and thereby affect the Utilities’ ability to proceed or could require design changes to the project overall. At this time we are unable to predict the timing or outcome of the permitting processes.

Additionally, due to concerns about the possible effect of carbon dioxide and other “greenhouse gases” on the environment, and particularly on climate change, there is considerable debate as to whether or not additional coal-fired generating stations should be built in the United States.  For example, U.S. Senator Harry Reid from the State of Nevada, Majority Leader of the U.S. Senate, has voiced objections to the construction of coal generating facilities in Nevada, including the Ely Energy Center. Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level which are aimed at the reduction of greenhouse gas emissions.    While the Utilities believe that the Ely Energy Center represents the best alternative for meeting the increasing electricity requirements of the State of Nevada, the Utilities cannot predict the outcome of pending or future legislative and rulemaking proposals, their effect on the permitting requirements for the Ely Energy Center described above, or their effect otherwise on the project overall, including future PUCN review and approval.  It is possible that the adoption of one or more such legislative or regulatory proposals could trigger a need to reevaluate the feasibility, economic and otherwise, of the Ely Energy Center as a coal generating facility or other aspects of the project overall.

If the Ely Energy Center is delayed or if the current planning assumptions for the project change materially, the Utilities would need to explore alternative sources of power for meeting the projected electricity demand in their service territories.  The most likely alternative to coal generation would involve increased use of natural gas, either through increased use of natural gas fueled purchased power or the construction of additional Utility-owned natural gas generating facilities, or a combination of both.  Such increased use of natural gas likely would further subject the Utilities and their customers to natural gas price volatility, as well as to any potential regional supply adequacy issues.

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 $405 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.  Currently, NPC and SPPC obtain 78.6 MWs and 184.9 MWs, respectively of renewable energy from sources such as geothermal, solar, hydroelectric, biomass and certain other forms of renewable energy.  In addition, NPC and SPPC have contracts with similar renewable providers for 160.4 MWs and 26.5 MWs, respectively, which are currently under development and NPC has an additional 139.5 MWs pending PUCN approval.  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.

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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.  Approximately 43.5 MWs 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’ PUCN-approved 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.  However, once in place, the Utilities do not trade these 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.  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.

In addition to cash on hand and the use of the Utilities’ revolving credit facilities, SPR and the Utilities may issue debt up to $1.1 billion consolidated, subject to certain limitations as discussed in the respective Liquidity and Capital Resources sections of SPR and the Utilities to meet its financial obligations.  Furthermore in September 2007, SPR, as a well known seasoned issuer, together with NPC and SPPC, filed a form S-3 shelf registration statement covering securities of SPR and the Utilities and which is expected to provide SPR and the Utilities with more timely access to the capital markets.

Currently, three of the four rating agencies now rate the Utilities’ senior secured debt investment grade.  The recent credit ratings upgrade will reduce the cost of borrowing under the Utilities’ revolving credit facilities.  In addition, the upgrades have the potential to provide SPR and the Utilities better access to capital markets and to reduce the cost of issuing additional long-term debt.  However, disruptions in the banking and capital markets not specifically related to SPR or the Utilities may affect their ability to access funding sources or cause an increase in the return required by investors.

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.

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SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Consolidated)

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later.  The Holding Company’s (stand alone) operating results included approximately $31.9 million and $38.9 million of long term debt interest costs for the nine months ended September 30, 2007 and 2006, respectively.

During the three months ended September 30, 2007, SPR’s recognized net income applicable to common stock of approximately $152.2 million compared to $222.2 million for the same period in 2006.  During the nine months ended September 30, 2007, SPR recognized net income applicable to common stock of approximately $193.6 million compared to $251.3 million for the same period in 2006.  Net income applicable to common stock was lower in the three months and nine months ended September 30, 2007 compared to the same period in 2006 primarily due to the reinstatement of deferred energy of approximately $116.2 million net of taxes recorded in 2006.  Partially offsetting this decrease was an increase to operating income as a result of increased rates, settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case, an increase in AFUDC due to the construction of NPC’s Clark Peaking Units and SPPC’s Tracy Generating Station and a decrease in interest charges.

As of September 30, 2007, NPC and SPPC had paid $23.5 million and $11.7 million, respectively, in dividends to SPR in 2007.  On November 1, 2007, NPC and SPPC declared a dividend to SPR of $10.7 million and $7.8 million, respectively.

ANALYSIS OF CASH FLOWS

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

Cash From Operating Activities  Cash flows from operating activities increased during the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to NPC’s increased operating income (excluding Reinstated Deferred Energy).  NPC’s Operating income (excluding Reinstated Deferred Energy) increased primarily as a result of increases in rates due to NPC’s GRC, the Western Energy Crisis Rate Case and the 2001 Deferred Energy Case, as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements.

Other factors contributing to the increase in cash flows were:

·   a decrease in payments made to suppliers;

·   the timing of payments;

·   improved credit terms with vendors;

·   a BTER rate which better reflects actual fuel and purchased power costs;

·   a decrease in interest expense paid; and

·   the net settlement with Enron in 2006.

This was partially offset by an increase in payments for Pension and Other Post Retirement Benefits of $100 million.

Cash Used by Investing Activities   Cash used by investing activities for the nine months ended September 30, 2007 increased compared to the same period in 2006 primarily due to expenditures for the Clark Peaking Units, the expansion of the Tracy Generating Station, the Ely Energy Center and utility infrastructure to support growth, offset by expenditures in 2006 for the Silverhawk and the Lenzie Generating Station.

Cash From Financing Activities   Cash from financing activities decreased during the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to net proceeds of $280.5 million from the issuance of 20 million shares of common stock in August 2006.  Also contributing to the decrease in cash was the payment of dividends in the third quarter of 2007 of approximately $17.7 million.  Partially offsetting these decreases was the issuance of new debt by NPC and SPPC in 2007.

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LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Overall Liquidity

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

Available Liquidity as of September 30, 2007 (in millions)
	SPR		NPC		SPPC
Cash and cash equivalents	$	27.2	$	44.9	$	28.6
Balance available on revolving credit facility	N/A			411.8		305.9
	$	27.2	$	456.7	$	334.5

In addition to cash on hand and the Utilities’ revolving credit facilities, SPR and the Utilities may issue debt up to $1.1 billion consolidated, subject to certain limitations discussed below and in the Utilities respective Liquidity and Capital Resources sections to meet their financial obligations.

SPR and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities.  To manage liquidity needs as a result of seasonal peaks in fuel requirements, SPR and the Utilities may use hedging activities.  However, to fund long-term 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.

Continued improvement in the credit ratings of SPR and the Utilities (see Credit Ratings below) has strengthened the liquidity position of the Utilities by allowing for the resumption of normal payment terms with our counterparties and the elimination of cash collateral requirements.  Existing collateral requirements with counterparties have been satisfied with letters of credit.  The recent credit rating upgrades reduce the cost of borrowing under the Utilities’ revolving credit facilities.  In addition, the upgrades have the potential to provide SPR and the Utilities better access to capital markets and to reduce the cost of issuing additional long-term debt.  However, disruptions in the banking and capital markets not specifically related to SPR or the Utilities may affect their ability to access funding sources or cause an increase in the return required by investors.

SPR has approximately $42.5 million payable of debt service obligations for 2007, of which SPR paid approximately $39.6 million during the nine months ended September 30, 2007.  SPR has approximately $2.9 million payable of debt service obligations remaining during 2007.  On September 12, 2007, SPR paid a dividend of $0.08 per share to common shareholders of record on August 24, 2007.  On November 1, SPR declared a dividend of $0.08 per share for shareholders of record on November 19, 2007.  The dividend will be paid on December 12.  The amount payable will be approximately $17.7 million, which SPR will pay from cash on hand.  SPR expects to meet its debt service obligations with cash on hand and/or through dividends from the Utilities.  See Dividends from Subsidiaries below.

During the nine months ended September 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.

Registration Statements

In September 2007, SPR, as a well-known seasoned issuer, filed a Form S-3 automatic shelf registration statement, together with NPC and SPPC, under which an indeterminate number of shares of common stock and principal amount of debt securities may be issued by SPR; an indeterminate principal amount of general and refunding mortgage securities may be issued by NPC; and an indeterminate principal amount of general and refunding mortgage securities may be issued by SPPC.  The registration statement is expected to allow the companies to gain access to the capital markets in a timelier manner.  It is effective for a three-year period.

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Factors Affecting Liquidity

Effect of Holding Company Structure

As of September 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 September 30, 2007, SPR, NPC, SPPC and their subsidiaries had approximately $4.3 billion of debt and other obligations outstanding, consisting of approximately $2.7 billion of debt at NPC, approximately $1.1 billion of debt at SPPC and approximately $550 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 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 September 30, 2007, NPC had paid $23.5 million in dividends to SPR and SPPC had paid $11.7 million in dividends to SPR in 2007.  On November 1, 2007, NPC and SPPC declared a $15.7 million and $7.8 million dividend, respectively, to SPR.

Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise 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 September 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, their financing agreements do not currently significantly restrict SPR’s and the Utilities’ ability to pay dividends.

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 November 1, 2007 the ratings are as follows:

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

     * Ratings are investment grade

In October 2007, Moody’s upgraded SPR’s corporate family rating to Ba1 from Ba2.  At the same time, Moody’s upgraded the senior unsecured debt at SPR to Ba3, and the senior secured debt at NPC and SPPC to Baa3, which is investment grade.  Moody’s rating outlook for SPR, NPC and SPPC is Stable.  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.  With the upgrade by Moody’s, three of the four rating agencies now rate the Utilities’ senior secured debt investment grade.

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

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 September 30, 2007, both Utilities were in compliance with these covenants.

Ability to Issue Debt

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

2.   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 September 30, 2007, SPR, NPC and SPPC would have been able to issue approximately $1.1 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 September 30, 2007, NPC recognized net income of approximately $133.1 million compared to net income of approximately $211.1 million for the same period in 2006.  During the nine months ended September 30, 2007, NPC recognized net income of approximately $161.3 million compared to net income of approximately $236.3 million for the same period in 2006.  The decrease in net income for the three and nine months ended September 30, 2007 was primarily due to the reinstatement of deferred energy of approximately $116.2 million net of taxes recorded in 2006.

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During the nine months ended September 30, 2007, NPC paid $23.5 million in dividends to SPR.  On November 1, 2007, NPC declared a dividend to SPR of $10.7 million.

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level.  Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is 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 Ended September 30,			Nine Months Ended September 30,
	2007	2006	Change from	2007	2006	Change from
			Prior Year  %			Prior Year  %
Operating Revenues:
Electric	$  894,226	$    776,235	15.2%	$1,887,499	$ 1,701,379	10.9%
Energy Costs:
Purchased power	313,487	289,975	8.1%	584,797	638,664	-8.4%
Fuel for power generation	166,284	183,622	-9.4%	471,142	425,138	10.8%
Deferral of energy costs-net	54,868	19,960	174.9%	149,531	53,748	178.2%
	$  534,639	$    493,557	8.3%	$1,205,470	$ 1,117,550	7.9%
Gross Margin before reinstatement of Deferred Energy Cost	$  359,587	$    282,678	27.2%	$   682,029	$    583,829	16.8%
Reinstatement of Deferred Energy Costs (1)	$            -	$    178,825	N/A	$             -	$    178,825	N/A
Gross Margin after reinstatement of Deferred Energy Costs	$  359,587	$    461,503	-22.1%	$   682,029	$   762,654	-10.6%
(1) Gross Margin, after reinstatement of deferred energy costs for the three and nine months ended September 30, 2007, decreased significantly from prior periods primarily due to the reinstatement of deferred energy costs as discussed further in the 2006 Form 10-K.

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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							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Electric Operating Revenues:
Residential	$	475,201	$	402,746		18.0	%	$	921,510	$	811,100		13.6	%
Commercial		147,821		135,031		9.5	%		365,854		338,159		8.2	%
Industrial		242,963		218,301		11.3	%		535,309		495,829		8.0	%
Retail  revenues		865,985		756,078		14.5	%		1,822,673		1,645,088		10.8	%
Other		28,241		20,157		40.1	%		64,826		56,291		15.2	%
Total Revenues	$	894,226	$	776,235		15.2	%	$	1,887,499	$	1,701,379		10.9	%
Retail sales in thousands
Of megawatt-hours (MWh)		7,502		7,105		5.6	%		17,283		16,567		4.3	%
Average retail revenue per MWh	$	115.43	$	106.41		8.5	%	$	105.46	$	99.30		6.2	%

NPC’s retail revenues increased for the three and nine months ended September 30, 2007, as compared to the same period in 2006, due to increases in retail rates, customer growth and hotter summer weather.  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 2.9%, and 3.2% for the three and nine months ended September 30, 2007, respectively.

Electric Operating Revenues – Other increased for the three months ended September, 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 for the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to a decrease in the reclassification of revenues associated with 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.

Purchased Power

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Purchased Power	$	313,487	$	289,975		8.1	%	$	584,797	$	638,664		(8.4	)%
Purchased Power in thousands
of MWhs		3,648		3,441		6.0	%		7,200		8,363		(13.9	)%
Average cost per MWh of
purchased power	$	85.93	$	84.27		2.0	%	$	81.22	$	76.37		6.4	%

NPC’s purchased power costs and megawatt hours (MWhs) increased for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to an increase in total system demand of approximately 4.0% as a result of customer growth and hotter weather.

For the nine months ended September 30, 2007, NPC’s purchased power costs and MWhs decreased primarily due to a decrease in volume compared to the same period in 2006.  Volume decreased as a result of NPC’s increased usage of internal generation, which was more economical than purchased power.  The average cost per MWh increased primarily due to fixed capacity charges associated with long term Qualified Facility (QF) contracts and other mid to long term contracts, coupled with a decrease in volume in the first two quarters of 2007.

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Fuel for Power Generation

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Fuel for Power Generation	$	166,284	$	183,622		-9.4	%	$	471,142	$	425,138		10.8	%
Thousands of MWhs generated		4,193		4,099		2.3	%		11,127		9,314		19.5	%
Average cost per MWh of
Generated Power	$	39.66	$	44.80		-11.5	%	$	42.34	$	45.65		-7.3	%

Fuel for power generation and the average cost per MWh decreased for the three months ended September 30, 2007 as compared to the same period in 2006 primarily due to lower natural gas prices partially offset by the cost of hedging activities.  Volume increased as a result of increased demand on NPC’s total system as a result of customer growth and hotter weather.

Fuel for power generation increased for the nine months ended September 30, 2007 as compared to the same time period in 2006 primarily due to an increase in volume, which resulted from increased usage of 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 decreased primarily due to lower natural gas prices, slightly offset by the increased usage of the Lenzie and Silverhawk generating stations which are natural gas-fired high efficiency combined cycle power plants and the cost of hedging activities.

Deferred Energy Costs - Net

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2007		2006			Change from Prior Year %	2007		2006			Change from Prior Year %
Reinstatement of deferred energy costs	$	-	$	(178,825	)	N/A	$	-	$	(178,825	)	N/A
Deferred energy costs - net	$	54,868	$	19,960		174.9%	$	149,531	$	53,748		178.2%

Reinstatement of deferred energy costs for the three and nine months ended September 30, 2006 represents the July 20, 2006 decision by the Nevada Supreme Court which allowed NPC to recover $178.8 million of previously disallowed deferred energy costs.  In March 2007, the PUCN approved the settlement agreement allowing NPC to recover such costs.   Reference further discussion in Note 3, Regulatory Actions, of the Condensed Notes to Consolidated Financial Statements.

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.

Amounts for the three months ended September 30, 2007 and 2006 include amortization of deferred energy costs of $73.0 million and $43.4 million, respectively; and an under-collection of amounts recoverable in rates of $18.2 million and $23.5 million, respectively.  Amounts for the nine months ended September 30, 2007 and 2006 include amortization of deferred energy costs of $137.8 million and $95.8 million, respectively; and an over-collection of amounts recoverable in rates of $11.8 million in 2007, compared to an under-collection of $42.1 million in 2006.

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Allowance for Funds Used During Construction (AFUDC)

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
	2007		2006		Change from Prior Year %			2007		2006		Change from Prior Year %
Allowance for other funds used during construction	$	4,701	$	1,986		136.7	%	$	11,046	$	10,140		8.9	%
Allowance for borrowed funds used during construction	$	3,936	$	1,978		99.0	%	$	9,189	$	10,050		-8.6	%
	$	8,637	$	3,964		117.9	%	$	20,235	$	20,190		0.2	%

AFUDC increased for the three months and nine months ended September 30, 2007, compared to the same period in 2006 primarily due to the start of construction of the Clark Peaking Units in 2007.  The debt component of AFUDC for the  nine months ended September 30, 2007 decreased compared to the same period in 2006, primarily due to lower debt costs which lowered the rate at which the debt component is calculated and a change to the debt to equity ratio.

Other (Income) and Expenses

	Three Months									Nine Months
	Ended September 30,									Ended September 30,
	2007			2006			Change from Prior Year %			2007			2006			Change from Prior Year %
Other operating expense	$	61,400		$	54,927			11.8	%	$	167,401		$	156,765			6.8	%
Maintenance expense	$	16,360		$	15,719			4.1	%	$	54,143		$	44,307			22.2	%
Depreciation and amortization	$	38,151		$	34,955			9.1	%	$	112,745		$	104,076			8.3	%
Interest charges on long-term debt	$	41,955		$	43,355			-3.2	%	$	123,029		$	132,285			-7.0	%
Interest charges-other	$	5,876		$	4,537			29.5	%	$	18,315		$	11,828			54.8	%
Interest accrued on deferred energy	$	(4,573	)	$	(4,786	)		-4.5	%	$	(11,849	)	$	(17,695	)		-33.0	%
Carrying charge for Lenzie		-		$	(10,040	)	N/A			$	(16,080	)	$	(23,206	)		-30.7	%
Reinstated interest on deferred energy		-			-		N/A			$	(11,076	)		-		N/A
Other income	$	(2,315	)	$	(4,080	)		-43.3	%	$	(10,345	)	$	(12,831	)		-19.4	%
Other expense	$	1,346		$	2,050			-34.3	%	$	8,772		$	6,353			38.1	%

Other operating expense increased for the three and nine months ended September 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 higher regulatory amortizations, partially offset by lower consulting fees and 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 in the second quarter and a reallocation of expenses to our joint facility partner which decreased other operating expenses.

Maintenance expense increased for the three months ended September 30, 2007, compared to the same period in 2006, mainly due to the timing of outages at Reid Gardner and increased maintenance cost for Silverhawk in 2007.

Maintenance expense increased for the nine months ended September 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 outages at Harry Allen in 2007 and increased maintenance cost for Silverhawk in 2007, partially offset by scheduled and forced outages at Clark Station in 2006.

Depreciation and amortization expenses increased during the three months and nine months ended September 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 2007 GRC, an adjustment for Silverhawk depreciation based on regulatory clarification, an increase to plant-in-service for Harry Allen Unit IV in May 2006, an increase to plant-in-service for Centennial Transmission Project in March 2007, offset by the overall reduction in depreciation rates, as ordered by the PUCN in NPC’s General Electric Rate Case in June 2007.

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Interest charges on Long-Term Debt decreased during the three months and nine months ended September 30, 2007, compared to the same periods in 2006, due primarily to various re-financings of debt in 2006 and 2007 at lower interest rates and a decrease in the use of the Revolving Credit Facility in the first nine months of 2007.  The Revolving Credit Facility was used in 2006 primarily to fund capital expenditures and fuel and purchased power expenses.  Interest expense for the Revolving Credit Facility for the three months and nine months ended September 30, 2007, was approximately $2.0 million and $5.6 million respectively, compared to $3.9 million and $11.8 million, respectively, for the same periods in the prior year.  See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2006 10-K 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 nine months ended September 30, 2007, as compared to the same periods in 2006, due to amortization of debt issuance and redemption costs, as well as additional interest associated with customer transmission deposits, and lease of property.

Interest accrued on deferred energy costs decreased for the three months and nine months ended September 30, 2007, compared to the same periods in 2006, due to lower deferred energy balances, partially offset by carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007.  See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further details of deferred energy balances and Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for further discussion of NPC’s Western Energy Crisis Rate Case.

Carrying charges for Lenzie represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie plant.  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 and nine months ended September 30, 2007 as compared to the same periods in 2006, as a result of 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.

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 nine months ended September 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 decreased during the three months ended September 30, 2007 compared to the same period in 2006, due to several items all of which were not individually significant.  Other expense increased during the nine months ended September 30, 2007 compared to the same period 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 and higher advertising expenses in 2007.

ANALYSIS OF CASH FLOWS

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

Cash From Operating Activities   Cash flows from operating activities increased during the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to increased operating income (excluding Reinstated Deferred Energy).  Operating income (excluding Reinstated Deferred Energy) increased primarily as a result of increases in rates due to NPC’s GRC, the Western Energy Crisis Rate Case and the 2001 Deferred Energy Case as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements.

In addition, operating cash flow (excluding Reinstated Deferred Energy) increased as a result of:

·   a decrease in payments made to suppliers;

·   the timing of payments;

·   improved credit terms with vendors, resulting in a decrease in deposits and prepayments;

·   a BTER rate which better reflects actual fuel and purchased power costs;

·   a decrease in interest expense paid; and

·   the net settlement with Enron in 2006.

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This was partially offset by an increase in payments for Pension and Other Post Retirement Benefits of $60.4 million.

Cash Used by Investing Activities   Cash used by investing activities for the nine months ended September 30, 2007 increased compared to the same period in 2006 primarily due to expenditures for the Clark Peaking Units, the Ely Energy Center and utility infrastructure to support the growth in the Las Vegas area, offset by expenditures in 2006 for the Silverhawk and the Lenzie Generating Station.

Cash From Financing Activities   Cash flows from financing activities decreased during the nine months ended September 30, 2007 compared to the same period in 2006 due to a decrease in financing activities and a capital contribution from SPR of $200 million in 2006.  Financing activities decreased as a result of the utilization of cash generated from operating activities.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary sources 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, capital expenditures, and the payment of interest on NPC’s outstanding indebtedness.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

	Available Liquidity as of September 30, 2007 (in millions)
Cash and cash equivalents	$	44.9
Balance available on Revolving Credit Facility (1)		411.8
	$	456.7

     ¹ As of November 1, 2007, NPC had approximately $545.1 million available under its revolving credit facility.

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

Continued improvement in the credit ratings of NPC (see Credit Ratings below) has strengthened the liquidity position of the company by allowing for the resumption of normal payment terms with our counterparties and the elimination of cash collateral requirements.  Existing collateral requirements with counterparties have been satisfied with letters of credit.  The recent credit rating upgrades reduce the cost of borrowing under NPC’s revolving credit facility.  In addition, the upgrades have the potential to provide NPC better access to capital markets and to reduce the cost of issuing additional long-term debt.  However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the return required by investors.

During the nine months ended September 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 and tenant improvements for Phase 1 and Phase 2 for the Beltway Business Park of approximately $52 million.

Registration Statements

In September 2007, NPC filed a Form S-3 automatic shelf registration statement under which an indeterminate principal amount of general and refunding mortgage securities may be issued by NPC.  The registration statement is expected to allow NPC to gain access to the capital markets in a timelier manner.  It is effective for a three-year period.

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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 SEC.  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.

Factors Affecting Liquidity

Financial Covenants

NPC's $600 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and amended in April 2006, contain two financial maintenance covenants.  The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.  As of September 30, 2007, NPC was in compliance with these covenants.

Ability to Issue Debt

Certain factors impact NPC’s ability to issue debt:

1.   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 September 30, 2007, NPC used approximately $950 million of the $2.56 billion authority, as such approximately $1.6 billion of the authority remains.

2.   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.  Bondable property includes plant in service and specific assets in construction work in progress.  As of September 30, 2007, NPC had the capacity to issue $710.6 million of General and Refunding Mortgage Securities.  The amount of bond capacity listed does not include eligible property in construction work in progress.

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 September 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 $2.2 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 $1.1 billion as of September 30, 2007.  Therefore, NPC is limited by SPR’s cap on additional indebtedness.

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Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $1.1 billion, depending on the Utilities’ combined usage of their respective revolving credit facilities at the time of the covenant calculation.

 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 September 30, 2007, $2.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  As mentioned in (2) above under “Ability to Issue Debt,” $710.6 million of additional securities may be issued under the General and Refunding Mortgage Indenture as of September 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 November 1, 2007 the ratings are as follows:

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

* Ratings are investment grade

In October 2007, Moody’s upgraded the senior secured debt at NPC to Baa3, which is investment grade.  Moody’s rating outlook for NPC is Stable.  In June 2007, 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.  With the upgrade by Moody’s, three of the four rating agencies now rate NPC’s senior secured debt investment grade.

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.

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 September 30, 2007, SPPC recognized earnings applicable to common stock of approximately $25.6 million compared to $20.0 million for the same period in 2006.  During the nine months ended September 30, 2007, SPPC recognized earnings applicable to common stock of approximately $57.5 million compared to $40.0 million for the same period in 2006.

During the nine months ended September 30, 2007, SPPC paid $11.7 million in dividends to SPR.  On November 1, 2007, SPPC declared a dividend to SPR of $7.8 million.

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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 Ended September 30,			Nine Months Ended September 30,
	2007	2006	Change from Prior Year %	2007	2006	Change from Prior Year %
Operating Revenues:
Electric	$     290,979	$    284,339	2.3%	$     789,214	$     767,133	2.9%
Gas	20,839	21,106	-1.3%	137,337	141,128	-2.7%
	$     311,818	$    305,445	2.1%	$     926,551	$     908,261	2.0%
Energy Costs:
Purchased power	$      96,980	$    106,158	-8.6%	$     266,599	$     267,914	-0.5%
Fuel for power generation	71,896	73,066	-1.6%	187,250	188,827	-0.8%
Gas purchased for resale	11,661	13,492	-13.6%	103,169	105,240	-2.0%
Deferral of energy costs-electric-net	11,792	(2,260)	-621.8%	44,423	20,973	111.8%
Deferral of energy costs-gas-net	2,594	1,130	129.6%	4,203	7,214	-41.7%
	$    194,923	$    191,586	1.7%	$     605,644	$     590,168	2.6%
Energy Costs by Segment:
Electric	$    180,668	$    176,964	2.1%	$     498,272	$     477,714	4.3%
Gas	14,255	14,622	-2.5%	107,372	112,454	-4.5%
	$    194,923	$    191,586	1.7%	$     605,644	$     590,168	2.6%
Gross Margin by Segment:
Electric	$    110,311	$    107,375	2.7%	$     290,942	$     289,419	0.5%
Gas	6,584	6,484	1.5%	29,965	28,674	4.5%
	$    116,895	$    113,859	2.7%	$     320,907	$     318,093	0.9%

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

Electric Operating Revenues

	Three Months Ended September 30,			Nine Months Ended September 30,
			Change from			Change from
	2007	2006	Prior Year %	2007	2006	Prior Year %
Electric Operating Revenues:
Residential	$  93,353	$  88,528	5.5%	$251,709	$239,109	5.3%
Commercial	111,701	107,502	3.9%	294,574	280,740	4.9%
Industrial	77,816	80,438	-3.3%	219,690	222,755	-1.4%
Retail  revenues	282,870	276,468	2.3%	765,973	742,604	3.1%
Other (1)	8,109	7,871	3.0%	23,241	24,529	-5.3%
Total Revenues	$290,979	$284,339	2.3%	$789,214	$767,133	2.9%
Retail sales in thousands
of megawatt-hours (MWh)	2,394	2,376	0.8%	6,632	6,546	1.3%
Average retail revenue per MWh	$  118.16	$  116.36	1.5%	$  115.50	$  113.44	1.8%

¹Primarily, wholesale, as discussed below

SPPC’s retail revenues increased for the three and nine months ended September 30, 2007 as compared to the same period in the prior year primarily due to customer growth and increases in retail rates.  The number of retail customers increased 1.6%, and 2.0% for the three and nine months ended September 30, 2007, respectively.  Retail rates increased as a result of SPPC’s various general, energy, and deferred energy cases.  For details see Management’s Discussion and Analysis, Regulatory Proceedings in the 2006 Form 10-K.  These increases were partially offset by lower industrial energy revenues and MWh’s as a result of two large industrial customers, moving to distribution-only and standby service.

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

Gas Operating Revenues

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Gas Operating Revenues:
Residential	$	11,384	$	11,369		0.1	%	$	76,592	$	78,901		-2.9	%
Commercial		5,415		5,448		-0.6	%		37,255		37,187		0.2	%
Industrial		2,600		2,895		-10.2	%		13,605		14,643		-7.1	%
Retail revenues		19,399		19,712		-1.6	%		127,452		130,731		-2.5	%
Wholesale revenue		943		776		21.5	%		7,922		8,275		-4.3	%
Miscellaneous		497		618		-19.6	%		1,963		2,122		-7.5	%
Total Revenues	$	20,839	$	21,106		-1.3	%	$	137,337	$	141,128		-2.7	%
Retail sales in thousands
of decatherms		1,318		1,324		-0.5	%		9,797		10,004		-2.1	%
Average retail revenue per
decatherm	$	14.72	$	14.89		-1.1	%	$	13.01	$	13.07		-0.5	%

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SPPC’s retail gas revenues was comparable for the three months ended September 30, 2007 compared to the same period in 2006.  SPPC’s retail gas revenues decreased for the nine months ended September 30, 2007 as compared to the same period in 2006 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 2.8%, and 3.3% for the three and nine months ended September 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.

Purchased Power

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Purchased Power	$	96,980	$	106,158		-8.6	%	$	266,599	$	267,914		-0.5	%
Purchased Power in thousands
of MWhs		1,347		1,399		-3.7	%		4,127		4,103		0.6	%
Average cost per MW of
Purchased Power	$	72.00	$	75.88		-5.1	%	$	64.60	$	65.30		-1.1	%

Purchased Power decreased for the three months ended September 30, 2007 as compared to the same period in 2006 primarily due to a decrease in natural gas prices and a decrease in the cost of power received through Idaho Power’s transmission system.  However, Idaho Power’s limited transmission capacity constrained SPPC’s ability to purchase additional power at those lower rates.

MWhs decreased for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to increased reliance on internal generation, which was more economical than Purchased Power.

Purchased Power decreased slightly for the nine months ended September 30, 2007 compared to the same period in 2006 primarily for the same reasons as discussed above for the three months ended September 30, 2007, offset by increased natural gas prices in the first six months of 2007 and a slight increase in SPPC’s total system demand.

Fuel for Power Generation

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Fuel for power generation	$	71,896	$	73,066		-1.6	%	$	187,250	$	188,827		-0.8	%
Thousands of MWh generated		1,235		1,129		9.4	%		2,996		2,930		2.3	%
Average fuel cost per MWh
of generated power	$	58.22	$	64.72		-10.0	%	$	62.50	$	64.45		-3.0	%

Fuel for power generation and the average cost per MWh decreased for the three and nine months ended September 30, 2007, as compared to the same period in 2006 due to a decrease in natural gas prices in 2007 and higher costs for hedging activities in 2006.

The volume of MWh generated increased in the three months ended September 30, 2007 compared to the same period in 2006 primarily due to an increase in internal generation, as a result of lower natural gas prices, an increase in customers and hotter weather.  The volume of MWh for the nine months ended September 30, 2007 increased compared to the same period in 2006 due to an increase in customers and hotter weather in the third quarter 2007.

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Gas Purchased for Resale

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2007		2006		Prior Year %			2007		2006		Prior Year %
Gas purchased for resale	$	11,661	$	13,492		-13.6	%	$	103,169	$	105,240		-2.0	%
Gas purchased for resale
(in thousands of decatherms)		1,553		1,464		6.1	%		11,348		11,470		-1.1	%
Average cost per decatherm	$	7.51	$	9.22		-18.5	%	$	9.09	$	9.18		-1.0	%

Gas purchased for resale and the average cost per decatherm decreased for the three and nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a decrease in natural gas prices in 2007 and higher costs for hedging activities in 2006.  The volume of gas purchased for resale increased for the three months ended September 30, 2007 as compared to the same period in 2006 due to an increase in customers in 2007.  The decrease in gas purchased for resale for the nine months ending September 2007 was primarily due to milder winter weather partially offset by an increase in customers.

Deferred Energy Costs

	Three Months								Nine Months
	Ended September 30,								Ended September 30,
	2007		2006			Change from Prior Year %			2007		2006		Change from Prior Year %
Deferred energy costs - electric - net	$	11,792	$	(2,260	)		-621.8	%	$	44,423	$	20,973		111.8	%
Deferred energy costs - gas - net		2,594		1,130			129.6	%		4,203		7,214		-41.7	%
	$	14,386	$	(1,130	)				$	48,626	$	28,187

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 September 30, 2007 and 2006 reflect amortization of deferred energy costs of $10.7 million and $11.8 million, respectively; and an over-collection of amounts recoverable in rates of $1.1 million in 2007, compared to an under-collection of $14.1 million in 2006.  For the nine months ended September 30, 2007 and 2006, amortization of deferred energy costs were $34.5 million and $34.4 million, respectively; with an over-collection of amounts recoverable in rates of $9.9 million in 2007, compared to an under-collection of $13.5 million in 2006.

Deferred energy costs - gas - net for the three months ended September 30, 2007 and 2006 reflect amortization of deferred energy costs of $0.1 million and $0.6 million, respectively; and an over-collection of amounts recoverable in rates of $2.5 million and $0.5 million, respectively.  For the nine months ended September 30, 2007 and 2006, amortization of deferred energy costs were $0.7 million and $4.8 million, respectively; with an over-collection of amounts recoverable in rates of $3.5 million and $2.4 million, respectively.

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Allowance for Funds Used During Construction (AFUDC)

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
	2007		2006		Change from Prior Year %			2007		2006		Change from Prior Year %
Allowance for other funds
used during construction	$	4,513	$	1,357		232.6	%	$	11,347	$	3,509		223.4	%
Allowance for borrowed funds used during construction	$	3,625	$	882		311.1	%	$	9,080	$	2,819		222.1	%
	$	8,138	$	2,239		263.5	%	$	20,427	$	6,328		222.8	%

AFUDC increased for the three and nine months ended September 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									Nine Months
	Ended September 30,									Ended September 30,
	2007			2006			Change from Prior Year %			2007			2006			Change from Prior Year %
Other operating expense	$	36,228		$	34,119			6.2	%	$	105,070		$	101,413			3.6	%
Maintenance expense	$	6,948		$	8,065			-13.8	%	$	23,543		$	24,833			-5.2	%
Depreciation and amortization	$	20,726		$	21,075			-1.7	%	$	62,043		$	66,037			-6.0	%
Interest charges on long-term debt	$	17,096		$	18,134			-5.7	%	$	49,746		$	53,958			-7.8	%
Interest charges-other	$	1,491		$	1,341			11.2	%	$	4,533		$	3,694			22.7	%
Interest accrued on deferred energy	$	(60	)	$	(1,433	)		-95.8	%	$	(1,171	)	$	(4,878	)		-76.0	%
Other income	$	(1,865	)	$	(2,491	)		-25.1	%	$	(6,707	)	$	(7,301	)		-8.1	%
Other expense	$	2,938		$	2,138			37.4	%	$	7,143		$	6,806			5.0	%

Other operating expense increased for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to several items all of which were not individually significant.

Other operating expense increased for the nine months ended September 30, 2007 compared to the same period in 2006, due to the settlement of contingency fees related to Enron in 2006 and higher regulatory amortizations and increased costs for claims in 2007.

Maintenance expense decreased for the three and nine months ended September 30, 2007 compared to the same period in 2006 primarily due to a planned outage at Ft. Churchill #1 during the third quarter in 2006 and planned outage for Ft. Churchill #2 that was delayed in 2007.

Depreciation and amortization expenses decreased for the three months ended September 30, 2007 compared to the same period in 2006 due to the retirement of plant assets as approved by the PUCN in SPPC’s General Electric and Gas Rate Cases in June 2006.

Depreciation and amortization expenses decreased for the nine months ended September 30, 2007 compared to the same period in 2006 due to the retirement of plant assets, as discussed above, and, a decrease in rates as ordered by the PUCN in SPPC’s General Electric and Gas Rate Cases in June 2006.

Interest charges on Long-Term Debt decreased during the three months and nine months ended September 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 issue of $300 million Series M notes in March 2006 and the issue of $325 million Series P notes in June 2007.  See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2006 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt of the Condensed Notes to Financial Statements.

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Interest charges-other increased during the three months and nine months ended September 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 nine months ended September 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 Notes to Financial Statements for further details of deferred energy balances.

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

Other expense increased during the three months ended and nine months ended September 30, 2007, as compared to the same period in 2006, primarily due to development costs associated with an information technology system conversion project.

ANALYSIS OF CASH FLOWS

Cash flows decreased for the nine months ended September 30, 2007 compared to the same period in 2006 due to an increase in cash used by investing activities and a decrease in cash from operating activities, partially offset by an increase in cash from financing activities.

Cash From Operating Activities   Cash from operating activities decreased as a result of a decrease in cash from accounts receivable and an increase in payments for Pension and Other Post Retirement Benefits of $36.5 million.  The decrease in cash from accounts receivable is primarily due to $49.7 million affiliated accounts receivable related to tax sharing agreements which were outstanding at December 31, 2005 and settled in 2006.

Cash Used by Investing Activities   Cash used by investing activities increased during the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to construction costs associated with the expansion of the Tracy Generating Station and utility infrastructure to support growth.

Cash From Financing Activities   Cash from financing activities increased during the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to the issuance of $325 million of SPPC’s 6.75% General and Refunding Mortgage Notes, Series P, a reduction in the redemption of debt and dividends paid to SPR from 2006.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary sources 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, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of September 30, 2007 (in millions)
Cash and Cash Equivalents	$	28.6
Balance available on Revolving Credit Facility (1)		305.9
	$	334.5

     ¹ As of November 1, 2007, SPPC had approximately $306 million available under its revolving credit facility.

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

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Continued improvement in the credit ratings of SPPC (see Credit Ratings below) has strengthened the liquidity position of the company by allowing for the resumption of normal payment terms with our counterparties and the elimination of cash collateral requirements.  Existing collateral requirements with counterparties have been satisfied with letters of credit.  The recent credit rating upgrades reduce the cost of borrowing under SPPC’s revolving credit facility.  In addition, the upgrades have the potential to provide SPPC better access to capital markets and to reduce the cost of issuing additional long-term debt.  However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the return required by investors.

During the nine months ended September 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.

Registration Statements

In September 2007, SPPC filed a Form S-3 automatic shelf registration statement under which an indeterminate principal amount of general and refunding mortgage securities may be issued by SPPC.  The registration statement is expected to allow SPPC to gain access to the capital markets in a timelier manner.  It is effective for a three-year period.

Financing Transactions

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 SEC.  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 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 September 30, 2007, SPPC was in compliance with these covenants.

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Ability to Issue Debt

Certain factors impact SPPC’s ability to issue debt:

1.   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 September 30, 2007, SPPC used approximately $675 million of the $1.42 billion authority, as such approximately $745 million of the authority remains.

2.   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.  Bondable property includes plant in service and specific assets in construction work in progress.  As of September 30, 2007, SPPC has the capacity to issue $324 million of General and Refunding Mortgage Securities.  The amount of bond capacity listed does not include eligible property in construction work in progress.

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 September 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 $761 million of additional debt.  The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including NPC and SPPC, at $1.1 billion as of September 30, 2007.  

Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $1.1 billion, depending on the Utilities’ combined usage of their revolving credit facilities at the time of the covenant calculation.

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 September 30, 2007, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  As mentioned in (2) above under “Ability to IssueDebt," $324 million of additional securities may be issued under the General and Refunding Mortgage Indenture as of September 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.

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Credit Ratings

SPPC is rated by four Nationally Recognized Statistical Rating Organizations:  S&P, Moody’s, Fitch and DBRS.  As of November 1, 2007 the ratings are as follows:

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

* Ratings are investment grade

In October 2007, Moody’s upgraded the senior secured debt at SPPC to Baa3, which is investment grade.  Moody’s rating outlook for SPPC is Stable.  In June 2007, 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.  With the upgrade by Moody’s, three of the four rating agencies now rate SPPC’s senior secured debt investment grade.

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.

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 SPPC 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.

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 are required to file annual Deferred Energy Accounting Adjustment (DEAA) cases, quarterly Base Tariff Energy Rate (BTER) Updates and triennial General Rate Cases (GRCs) in Nevada.  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.  As of September 30, 2007, NPC’s and SPPC’s balance sheet included approximately $361.6 million and $11.6 million, respectively, of deferred energy costs of which $362.7 and $27.2 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.  A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

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Rate case applications filed in 2006 and 2007, as well as other regulatory matters such as, the Utilities’ Integrated Resource Plans 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 10K.

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 September 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		$	561,023
Average Interest Rate		-			-			-			-			-			7.75	%		7.75	%
NPC
Fixed Rate	$	5		$	12		$	-		$	-		$	364,000		$	1,916,579		$	2,280,596		$	2,313,387
Average Interest Rate		8.17	%		8.17	%		-			-			8.14	%		6.35	%		6.64	%
Variable Rate	$	-		$	-		$	15,000		$	150,000		$	-		$	192,500		$	357,500		$	357,500
Average Interest Rate		-			-			4.21	%		6.74	%		-			3.93	%		5.12	%
SPPC
Fixed Rate	$	534		$	101,643		$	600		$	-		$	-		$	725,000		$	827,777		$	826,918
Average Interest Rate		6.40	%		7.96	%		6.40	%		-			-			6.37	%		6.57	%
Variable Rate	$	-		$	-		$	-		$	25,000		$	-		$	348,250		$	373,250		$	373,250
Average Interest Rate		-			-			-			6.01	%		-			3.72	%		3.87	%
Total Debt	$	539		$	101,655		$	15,600		$	175,000		$	364,000		$	3,731,538		$	4,388,332		$	4,432,078

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 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 $6.4 million as of September 30, 2007, which decreased from the $31.1 million balance at December 31, 2006.  The decrease from December 31, 2006 is primarily due to primarily due to summer tolling agreements that terminated during the period ended September 30, 2007.

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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 September 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 third 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 and June 30, 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 July 2008.

Lawsuit Against Natural Gas Providers

In April 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders.  In July 2003, SPR and NPC filed a First Amended Complaint.  A Second Amended Complaint was filed in June 2004, which named three different groups of defendants:  (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric.  On December 13, 2005, the District Court dismissed SPR and NPC’s claims.  SPR and NPC appealed that decision to the Ninth Circuit Court of Appeals.  Subsequently, SPR abandoned its appeal and the matter proceeded only with respect to NPC.  On September 21, 2007, the Ninth Circuit reversed the District Court’s decision.  On October 5, 2007, defendants filed a petition for rehearing with the Ninth Circuit.  Management cannot predict the timing or outcome of a decision on the petition for rehearing.

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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, filed their opposition to these Petitions on August 6, 2007.  On September 25, 2007, the U.S. Supreme Court granted certiorari and ordered the submission of briefs in November of 2007 and January and February 2008.  Oral argument before the U.S. Supreme has not been scheduled.  The Utilities cannot predict the outcome of this matter.

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 $39.1 million.  Expenditures for 2007 through 2010 are projected to be approximately $8.8 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 for the school district.  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.

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Clark Station

As disclosed in prior filings, in May 2006, the EPA, by letter from the DOJ, notified NPC that it intended 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 at Clark Station.  NPC then entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations and in August 2007, a final Consent Decree between NPC and the EPA was entered with the 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.  

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 and June 30, 2007, except as discussed below.

SPR’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly NPC and SPPC. SPR and the Utilities have the ability to issue a significant amount of additional indebtedness under the terms of their various financing agreements.

Because SPR is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing indebtedness and other future liabilities, including claims by the Utilities’ trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. SPR conducts substantially all of its operations through its subsidiaries, and thus SPR’s ability to meet its obligations under its indebtedness will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to SPR.  As of September 30, 2007, the Utilities had approximately $4.3 billion of debt outstanding. The terms of SPR’s indebtedness restrict the amount of additional indebtedness that SPR and the Utilities may issue. Based on SPR’s September 30, 2007 financial statements, assuming an interest rate of 7%, SPR’s indebtedness restrictions would allow SPR and the Utilities to issue up to approximately $1.1 billion of additional indebtedness in the aggregate, unless the indebtedness being issued is specifically permitted under the terms of SPR’s indebtedness. In addition, NPC and SPPC are subject to restrictions under the terms of their various financing agreements on their ability to issue additional indebtedness.

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

None.

ITEM 3.                      DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5.                      OTHER INFORMATION

On November 2, 2007, SPR announced that E. Kevin Bethel, CPA, will be joining SPR as the chief accounting officer, effective December 10, 2007.  Mr. Bethel, 43, will also serve as the chief accounting officer of SPPC and NPC.  Prior to joining SPR, Mr. Bethel served as the assistant controller for American Electric Power since March 2007, director of utility general and regulated accounting from 2004 to 2007, and director of investment accounting from 2001 to 2004.  Mr. Bethel has served in various accounting positions within the utility industry since 1991.

As of December 10, 2007, John E. Brown will no longer be the current principal accounting officer of SPR and each of the Utilities, but will retain the position of controller for each company and will report to Mr. Bethel in his capacity as chief accounting officer.

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ITEM 6.   EXHIBITS

(10)    Nevada Power Company:

10.1    Joint Tenant Contract, dated September 18, 2007, between Nevada Power Company as Tenant, and Beltway Business Park Warehouse No. 2, LLC as Owner, relating to Nevada Power Company’s South Operations Center facility.

(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.

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SIGNATURES

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

                                                                Sierra Pacific Resources

                           (Registrant)

                 Date:      November 1, 2007                                                By:   /s/ William D. Rogers   

                                         William D. Rogers

                                   Chief Financial Officer

                                                               (Principal Financial Officer)

                  Date:      November 1, 2007                                              By:    /s/ John E. Brown

                                      John E. Brown

                                   Controller

                                      (Principal Accounting Officer)

Nevada Power Company

                        (Registrant)

                  Date:      November 1, 2007                                              By:   /s/ William D. Rogers   

                                        William D. Rogers

                                  Chief Financial Officer

                                                              (Principal Financial Officer)

                  Date:      November 1, 2007                                             By:   /s/ John E. Brown

                                    John E. Brown

                                 Controller

                                    (Principal Accounting Officer)

                                                                                                         Sierra Pacific Power Company

                         (Registrant)

                  Date:      November 1, 2007                                              By:   /s/ William D. Rogers   

                                        William D. Rogers

                                   Chief Financial Officer

                                                              (Principal Financial Officer)

                  Date:      November 1, 2007                                              By:   /s/ John E. Brown

                                     John E. Brown

                                  Controller

                                    (Principal Accounting Officer)