form10-q.htm

Table of Contents

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)

Acronym/Term		Meaning

2008 Form 10-K		NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2008
AFUDC		Allowance for Funds Used During Construction or Allowance for Borrowed Funds Used During Construction
BCP		Bureau of Consumer Protection
BOD		Board of Directors
BTER		Base Tariff Energy Rate
BTGR		Base Tariff General Rate
CalPeco		California Pacific Electric Company
Calpine		Calpine Corporation
Clark Generating Station		550 megawatt nominally rated William Clark Generating Station
Clark Peaking Units		600 megawatt nominally rated peaking units at the William Clark Generating Station
CPUC		California Public Utilities Commission
CWIP		Construction Work-In-Progress
d/b/a		Doing business as
DBRS		Dominion Bond Rating Service
DEAA		Deferred Energy Accounting Adjustment
DOS		Distribution Only Service
DSM		Demand Side Management
Dth		Decatherm
EEC		Ely Energy Center
EPA		Environmental Protection Agency
EPS		Earnings Per Share
FASB		Financial Accounting Standards Board
FASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd.
GAAP		Accounting Principles Generally Accepted in the United States
GRC		General Rate Case
Harry Allen Generating Station		142 megawatt nominally rated Harry Allen Generating Station
Higgins Generating Station		598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
IRS		Internal Revenue Service
Lenzie Generating Station		1,102 megawatt nominally rated Chuck Lenzie Generating Station
MMBtu		Million British Thermal Units
Moody’s		Moody’s Investors Services, Inc.
MW		Megawatt
MWh		Megawatt hour
Navajo Generating Station		255 megawatt nominally rated Navajo Generating Station
NEICO		Nevada Electrical Investment Company
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NPC		Nevada Power Company d/b/a NV Energy
NPC’s Indenture		NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank of New York Mellon, as Trustee
NVE		NV Energy, Inc.
ON Line		250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC		Portfolio Energy Credit
Piñon Pine		Piñon Pine Coal Gasification Demonstration Project
Portfolio Standard		Renewable Energy Portfolio Standard
PUCN		Public Utilities Commission of Nevada
Reid Gardner Generating Station		325 megawatt nominally rated Reid Gardner Generating Station
ROE		Return on Equity
ROR		Rate of Return
S&P		Standard & Poor’s
Salt River		Salt River Project
SEC		United States Securities and Exchange Commission
Silverhawk Generating Station		395 megawatt nominally rated Silverhawk Generating Station
SPPC		Sierra Pacific Power Company d/b/a NV Energy
SPPC’s Indenture		SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and the Bank of New York Mellon, as Trustee
SPR		Sierra Pacific Resources
TMWA		Truckee Meadows Water Authority
Tracy Generating Station		541 megawatt nominally rated Frank A. Tracy Generating Station
U.S.		United States of America
Utilities		Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station		261 megawatt nominally rated Valmy Generating Station
WSPP		Western Systems Power Pool

Table of Contents

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		September 30,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	10,691,636	$	10,175,741
Less accumulated provision for depreciation			2,824,428		2,603,287
			7,867,208		7,572,454
Construction work-in-progress			672,293		605,163
			8,539,501		8,177,617

Investments and other property, net			25,106		25,181

Current Assets:
Cash and cash equivalents			95,574		54,359
Accounts receivable less allowance for uncollectible accounts:
	2009 - $33,493, 2008 - $32,884		528,775		410,184
Deferred energy costs (Note 3)			-		50,436
Materials, supplies and fuel, at average cost			121,265		124,271
Risk management assets (Note 6)			30,185		16,118
Current income taxes receivable			13,200		5,487
Deferred income taxes			90,495		49,996
Other			47,031		52,633
			926,525		763,484
Deferred Charges and Other Assets:
Deferred energy costs (Note 3)			141,568		231,027
Regulatory assets			1,205,872		1,415,286
Regulatory asset for pension plans			366,829		413,544
Risk management assets (Note 6)			21,580		9,959
Other			167,735		169,266
			1,903,584		2,239,082
Assets Held for Sale (Note 12)			140,878		142,506
TOTAL ASSETS		$	11,535,594	$	11,347,870
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,243,820	$	3,131,186
Long-term debt			5,549,052		5,266,982
			8,792,872		8,398,168
Current Liabilities:
Current maturities of long-term debt			9,286		9,291
Accounts payable			304,108		400,084
Accrued expenses			125,924		131,720
Risk management liabilities (Note 6)			109,055		313,846
Deferred energy costs (Note 3)			109,183		28,546
Other			66,727		87,060
			724,283		970,547
Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
Deferred income taxes			1,080,655		920,481
Deferred investment tax credit			23,261		25,923
Accrued retirement benefits			227,760		288,841
Risk management liabilities			1,069		53,403
Regulatory liabilities			366,541		350,526
Other			289,170		315,881
			1,988,456		1,955,055
Liabilities Held for Sale (Note 12)			29,983		24,100
TOTAL CAPITALIZATION AND LIABILITIES		$	11,535,594	$	11,347,870

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

Table of Contents

NV ENERGY, INC.
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

OPERATING REVENUES:
Electric	$	1,199,254		$	1,098,744		$	2,680,204		$	2,624,832
Gas		19,745			19,379			132,686			137,125
Other		8			8			25			19
		1,219,007			1,118,131			2,812,915			2,761,976
OPERATING EXPENSES:
Operation:
Fuel for power generation		250,085			332,872			684,474			825,105
Purchased power		313,828			383,329			634,185			828,635
Gas purchased for resale		11,269			13,760			101,457			108,288
Deferral of energy costs - electric - net		73,557			(89,575	)		213,132			(56,679	)
Deferral of energy costs - gas - net		2,286			(725	)		1,923			(2,296	)
Other		107,992			105,087			332,555			295,409
Maintenance		20,187			20,337			82,219			64,931
Depreciation and amortization		82,541			59,245			240,912			185,656
Taxes:
Income taxes		80,780			61,148			71,208			82,695
Other than income		15,177			13,701			43,577			40,266
		957,702			899,179			2,405,642			2,372,010
OPERATING INCOME		261,305			218,952			407,273			389,966

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		4,327			7,865			19,093			32,935
Interest accrued on deferred energy		(1,799	)		2,349			(873	)		4,042
Other income		7,749			6,583			31,209			24,787
Other expense		(2,387	)		(3,007	)		(17,425	)		(10,804	)
Income taxes		(1,745	)		(4,263	)		(9,496	)		(16,451	)
		6,145			9,527			22,508			34,509
Total Income Before Interest Charges		267,450			228,479			429,781			424,475

INTEREST CHARGES:
Long-term debt		82,865			75,483			244,613			215,826
Other		5,618			8,391			22,230			23,092
Allowance for borrowed funds used during construction		(3,679	)		(6,178	)		(15,847	)		(25,418	)
		84,804			77,696			250,996			213,500

NET INCOME	$	182,646		$	150,783		$	178,785		$	210,975

Amount per share basic and diluted - (Note 8)
Net Income per share - basic and diluted	$	0.78		$	0.64		$	0.76		$	0.90

Weighted Average Shares of Common Stock Outstanding - basic		234,629,761			234,096,559			234,479,605			233,975,552
Weighted Average Shares of Common Stock Outstanding - diluted		235,368,919			234,655,132			235,025,554			234,499,269
Dividends Declared Per Share of Common Stock	$	0.10		$	0.08		$	0.30		$	0.24

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

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NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Nine Months Ended
	September 30,
	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	178,785		$	210,975
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		240,912			185,656
Deferred taxes and deferred investment tax credit		115,389			172,425
AFUDC		(19,093	)		(32,935	)
Deferred energy costs, net of amortizations		221,321			(63,374	)
Other, net		11,188			13,087
Changes in certain assets and liabilities:
Accounts receivable		(124,976	)		(139,755	)
Materials, supplies and fuel		3,246			(12,682	)
Other current assets		5,602			4,005
Accounts payable		(28,001	)		(33,712	)
Accrued retirement benefits		(36,881	)		(13,839	)
Other current liabilities		(26,282	)		33,403
Risk management assets and liabilities		3,175			(1,763	)
Other deferred assets		(11,248	)		(34,433	)
Other regulatory assets		(52,671	)		(50,702	)
Other deferred liabilities		(25,291	)		(12,102	)
Net Cash from Operating Activities		455,175			224,254

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(670,023	)		(671,918	)
Customer advances for construction		(6,009	)		(11,018	)
Contributions in aid of construction		48,956			57,437
Investments and other property - net		(19	)		4,312
Net Cash used by Investing Activities		(627,095	)		(621,187	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,273,649			1,420,002
Retirement of long-term debt		(994,275	)		(871,987	)
Sale of Common Stock		4,162			5,195
Dividends paid		(70,401	)		(56,272	)
Net Cash from Financing Activities		213,135			496,938

Net Increase in Cash and Cash Equivalents		41,215			100,005
Beginning Balance in Cash and Cash Equivalents		54,359			129,140
Ending Balance in Cash and Cash Equivalents	$	95,574		$	229,145

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	257,593		$	213,857
Income taxes	$	14		$	16,897
Significant non-cash investing transactions:
Accrued additions to utility plant as of September 30,	$	76,006		$	85,580

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

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		September 30,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	7,318,200	$	6,884,033
Less accumulated provision for depreciation			1,678,057		1,500,502
			5,640,143		5,383,531
Construction work-in-progress			557,754		514,096
			6,197,897		5,897,627

Investments and other property, net			19,702		19,701

Current Assets:
Cash and cash equivalents			30,784		28,594
Accounts receivable less allowance for uncollectible accounts:
	2009 - $30,919, 2008 - $30,621		397,908		238,379
Deferred energy costs (Note 3)			-		50,436
Materials, supplies and fuel, at average cost			69,933		74,103
Risk management assets (Note 6)			23,754		11,724
Intercompany income taxes receivable			23,556		20,695
Deferred income taxes			44,091		2,682
Other			32,181		34,657
			622,207		461,270
Deferred Charges and Other Assets:
Deferred energy costs (Note 3)			141,568		231,027
Regulatory assets			839,973		971,354
Regulatory asset for pension plans			178,607		187,894
Risk management assets (Note 6)			17,001		7,346
Other			124,096		127,928
			1,301,245		1,525,549
TOTAL ASSETS		$	8,141,051	$	7,904,147
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,691,551	$	2,627,567
Long-term debt			3,701,308		3,385,106
			6,392,859		6,012,673
Current Liabilities:
Current maturities of long-term debt			9,286		8,691
Accounts payable			222,497		262,552
Accounts payable, affiliated companies			26,513		32,901
Accrued expenses			80,300		80,069
Dividends declared			7,500		-
Risk management liabilities (Note 6)			65,907		222,856
Deferred energy costs (Note 3)			4,762		-
Other			51,639		72,762
			468,404		679,831
Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
Deferred income taxes			784,098		635,523
Deferred investment tax credit			8,983		10,001
Accrued retirement benefits			74,238		103,023
Risk management liabilities (Note 6)			481		35,241
Regulatory liabilities			200,766		188,709
Other			211,222		239,146
			1,279,788		1,211,643
TOTAL CAPITALIZATION AND LIABILITIES		$	8,141,051	$	7,904,147

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

Table of Contents

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
OPERATING REVENUES:
Electric	$	933,520		$	826,825		$	1,945,818		$	1,866,220

OPERATING EXPENSES:
Operation:
Fuel for power generation		160,960			240,027			455,355			613,968
Purchased power		288,248			319,324			541,746			577,161
Deferral of energy costs-net		46,911			(80,191	)		144,910			(44,107	)
Other		68,521			69,432			206,771			189,144
Maintenance		12,014			12,469			58,280			42,727
Depreciation and amortization		54,996			37,902			160,869			120,855
Taxes:
Income taxes		75,214			54,595			57,702			69,592
Other than income		8,970			8,266			26,394			24,015
		715,834			661,824			1,652,027			1,593,355
OPERATING INCOME		217,686			165,001			293,791			272,865

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,385			6,543			16,558			21,093
Interest accrued on deferred energy		248			2,803			2,891			5,681
Other income		3,776			4,116			18,726			12,970
Other expense		(1,537	)		(2,028	)		(12,335	)		(5,045	)
Income taxes		(1,612	)		(3,828	)		(8,155	)		(11,350	)
		4,260			7,606			17,685			23,349
Total Income Before Interest Charges		221,946			172,607			311,476			296,214

INTEREST CHARGES:
Long-term debt		56,672			46,662			166,492			129,283
Other		4,498			6,737			17,526			17,952
Allowance for borrowed funds used during construction		(2,815	)		(5,128	)		(13,483	)		(16,503	)
		58,355			48,271			170,535			130,732

NET INCOME	$	163,591		$	124,336		$	140,941		$	165,482

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

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Nine Months Ended
	September 30,
	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	140,941		$	165,482
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		160,869			120,855
Deferred taxes and deferred investment tax credit		100,126			89,543
AFUDC		(16,558	)		(21,093	)
Deferred energy costs, net of amortizations		144,656			(49,647	)
Other, net		(14,497	)		2,659
Changes in certain assets and liabilities:
Accounts receivable		(162,390	)		(143,891	)
Materials, supplies and fuel		4,171			(9,531	)
Other current assets		2,476			(1,233	)
Accounts payable		3,323			(21,048	)
Accrued retirement benefits		(29,766	)		(1,741	)
Other current liabilities		(20,891	)		38,775
Risk management assets and liabilities		2,113			(989	)
Other deferred assets		(8,453	)		(35,291	)
Other regulatory assets		(42,348	)		(36,540	)
Other deferred liabilities		(30,079	)		(8,113	)
Net Cash from Operating Activities		233,693			88,197

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(517,985	)		(506,680	)
Customer advances for construction		(1,974	)		(12,951	)
Contributions in aid of construction		42,561			49,108
Investments and other property - net		(94	)		2,719
Net Cash used by Investing Activities		(477,492	)		(467,804	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		944,326			878,034
Retirement of long-term debt		(628,837	)		(435,787	)
Additional investment by parent company		-			133,000
Dividends paid		(69,500	)		(54,907	)
Net Cash from Financing Activities		245,989			520,340

Net Increase in Cash and Cash Equivalents		2,190			140,733
Beginning Balance in Cash and Cash Equivalents		28,594			37,001
Ending Balance in Cash and Cash Equivalents	$	30,784		$	177,734

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	171,955		$	120,749
Income taxes	$	2		$	15,534
Significant non-cash investing transactions:
Accrued additions to utility plant as of September 30,	$	69,842		$	76,749

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

Table of Contents

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		September 30,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	3,373,436	$	3,291,708
Less accumulated provision for depreciation			1,146,371		1,102,785
			2,227,065		2,188,923
Construction work-in-progress			114,539		91,067
			2,341,604		2,279,990

Investments and other property, net			328		403

Current Assets:
Cash and cash equivalents			58,392		21,411
Accounts receivable less allowance for uncollectible accounts:
	2009 - $2,574; 2008 - $2,262		130,649		171,729
Materials, supplies and fuel, at average cost			51,268		50,132
Risk management assets (Note 6)			6,431		4,394
Intercompany income taxes receivable			48,029		64,932
Deferred income taxes			37,767		12,253
Other			14,239		17,631
			346,775		342,482
Deferred Charges and Other Assets:
Regulatory assets			365,899		443,932
Regulatory asset for pension plans			181,425		218,550
Risk management assets (Note 6)			4,579		2,613
Other			36,461		33,959
			588,364		699,054
Assets Held for Sale (Note 12)			140,878		142,506
TOTAL ASSETS		$	3,417,949	$	3,464,435
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	994,495	$	877,961
Long-term debt			1,362,002		1,395,987
			2,356,497		2,273,948
Current Liabilities:
Current maturities of long-term debt			-		600
Accounts payable			66,799		109,410
Accounts payable, affiliated companies			14,822		17,433
Accrued expenses			39,435		37,787
Dividends declared			-		96,800
Risk management liabilities (Note 6)			43,148		90,990
Deferred energy costs (Note 3)			104,421		28,546
Other			15,089		14,298
			283,714		395,864
Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
Deferred income taxes			348,793		287,251
Deferred investment tax credit			14,278		15,922
Accrued retirement benefits			147,238		180,209
Risk management liabilities (Note 6)			588		18,162
Regulatory liabilities			165,775		161,817
Other			71,083		107,162
			747,755		770,523
Liabilities Held for Sale (Note 12)			29,983		24,100
TOTAL CAPITALIZATION AND LIABILITIES		$	3,417,949	$	3,464,435

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

Table of Contents

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
OPERATING REVENUES:
Electric	$	265,734		$	271,919		$	734,386		$	758,612
Gas		19,745			19,379			132,686			137,125
		285,479			291,298			867,072			895,737
OPERATING EXPENSES:
Operation:
Fuel for power generation		89,125			92,845			229,119			211,137
Purchased power		25,580			64,005			92,439			251,474
Gas purchased for resale		11,269			13,760			101,457			108,288
Deferral of energy costs - electric - net		26,646			(9,384	)		68,222			(12,572	)
Deferral of energy costs - gas - net		2,286			(725	)		1,923			(2,296	)
Other		38,843			35,474			123,748			103,744
Maintenance		8,173			7,868			23,939			22,204
Depreciation and amortization		27,545			21,343			80,043			64,801
Taxes:
Income taxes		10,445			10,602			24,275			24,213
Other than income		6,162			5,402			17,046			16,128
		246,074			241,190			762,211			787,121
OPERATING INCOME		39,405			50,108			104,861			108,616

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		942			1,322			2,535			11,842
Interest accrued on deferred energy		(2,047	)		(454	)		(3,764	)		(1,639	)
Other income		3,792			2,367			12,299			11,331
Other expense		(813	)		(749	)		(4,601	)		(5,430	)
Income taxes		(226	)		(683	)		(1,651	)		(5,210	)
		1,648			1,803			4,818			10,894
Total Income Before Interest Charges		41,053			51,911			109,679			119,510

INTEREST CHARGES:
Long-term debt		16,760			18,635			49,820			55,975
Other		891			1,407			4,017			4,398
Allowance for borrowed funds used during construction		(864	)		(1,050	)		(2,364	)		(8,915	)
		16,787			18,992			51,473			51,458

NET INCOME	$	24,266		$	32,919		$	58,206		$	68,052

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

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Nine Months Ended
	September 30,
	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	58,206		$	68,052
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		80,043			64,801
Deferred taxes and deferred investment tax credit		38,782			28,472
AFUDC		(2,535	)		(11,842	)
Deferred energy costs, net of amortizations		76,665			(13,727	)
Other, net		24,917			14,476
Changes in certain assets and liabilities:
Accounts receivable		59,312			4,152
Materials, supplies and fuel		(896	)		(3,142	)
Other current assets		3,391			5,488
Accounts payable		(27,013	)		(16,267	)
Accrued retirement benefits		(7,545	)		(15,789	)
Other current liabilities		2,285			2,864
Risk management assets and liabilities		1,062			(774	)
Other deferred assets		(2,796	)		858
Other regulatory assets		(10,323	)		(14,162	)
Other deferred liabilities		(32,505	)		(2,142	)
Net Cash from Operating Activities		261,050			111,318

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(152,038	)		(165,238	)
Customer advances for construction		(4,035	)		1,933
Contributions in aid of construction		6,395			8,329
Investments and other property - net		76			1,597
Net Cash used by Investing Activities		(149,602	)		(153,379	)

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		329,324			541,968
Retirement of long-term debt		(365,291	)		(436,038	)
Investment by parent company		90,300			20,000
Dividends paid		(128,800	)		(78,333	)
Net Cash from (used by) Financing Activities		(74,467	)		47,597

Net Increase in Cash and Cash Equivalents		36,981			5,536
Beginning Balance in Cash and Cash Equivalents		21,411			23,807
Ending Balance in Cash and Cash Equivalents	$	58,392		$	29,343

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	50,387		$	54,849
Income taxes	$	12		$	19
Significant non-cash investing transactions:
Accrued additions to utility plant as of September 30,	$	6,164		$	8,831

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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, Tuscarora Gas Pipeline Company, which was dissolved in 2008, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Pacific Energy Company, Sierra Water Development Company and Sierra Gas Holding Company. All intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with GAAP 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 NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2008 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the three and nine months ended September 30, 2009, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

Certain financial statement line items for prior periods have been regrouped or reclassified to conform with current year presentation. The regroupings or reclassifications have not affected previously reported results of operations or common shareholders’ equity.

Recent Accounting Standards Updates

Fair Value Measurements and Disclosures

In February 2008, the FASB issued transition guidance which deferred the effective date of applying fair value measurements to nonfinancial assets and nonfinancial liabilities which are nonrecurring. The transition guidance was effective for NVE and the Utilities beginning January 1, 2009. The adoption of this guidance did not have a material impact on the consolidated financial statements of NVE and the Utilities.

In April 2009, the FASB issued additional guidance on measuring the fair value of financial instruments when markets become inactive and quoted prices may reflect distressed transactions. The provisions of this guidance are effective for NVE and the Utilities as of June 30, 2009. The adoption did not have an effect on the consolidated financial statements of NVE and the Utilities.

In August 2009, the FASB issued an update on the Fair Value Measurements and Disclosures Topic as reflected in the FASB Accounting Standards Codification for the fair value of liabilities. This update provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. The provisions of this guidance are effective for NVE and the Utilities beginning October 1, 2009. NVE and the Utilities do not expect the adoption to have a significant impact on the consolidated financial statements.

Derivatives and Hedging

In March 2008, the FASB issued an amendment of its existing guidance effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The purpose of the amendment is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. NVE and the Utilities adopted the amendment beginning January 1, 2009. See Note 6, Derivatives and Hedging Activities.

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Financial Instruments

In April 2009, the FASB issued transition guidance requiring disclosure of fair values of certain financial instruments in interim financial statements. The provisions of the transition guidance was effective for NVE and the Utilities as of June 30, 2009. See Note 5, Fair Value of Financial Instruments.

Subsequent Events

In May 2009, the FASB issued guidance which establishes the accounting principles and disclosure requirements for subsequent events. The guidance requires an entity to disclose the date through which subsequent events have been evaluated, as well as whether that date is the date the financial statements were issued or the date the financial statements were available to be issued. NVE and the Utilities evaluated subsequent events at the time the financial statements were issued, which was October 29, 2009. The guidance was effective for NVE and the Utilities as of June 30, 2009.

Consolidations of Variable Interest Entities

In June 2009, the FASB amended existing guidance related to the Consolidation of Variable Interest Entities. The amendment requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics: a) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. The amendment will be effective for NVE and the Utilities beginning January 1, 2010. NVE and the Utilities are currently evaluating the impact of the adoption of this amendment.

FASC and the Hierarchy of Generally Accepted Accounting Principles

In June 2009, the FASB issued guidance related to the FASC, which became the single source of authoritative GAAP, other than guidance put forth by the SEC. All other accounting literature not included in the codification will be considered non-authoritative. The guidance is effective for NVE and the Utilities for the quarterly period ending September 30, 2009 and will impact the current disclosure of the financial statements since all references to authoritative accounting literature will be topic references in accordance with the FASC.

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NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as required by the Segment Reporting Topic of the FASC) which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative thresholds for separate disclosure.

Operational information of the different business segments is set forth below based on the nature of products and services offered. NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin. Gross margin, which the Utilities calculate as operating revenues less energy costs, provides a measure of income available to support the other operating expenses of the Utilities. Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands).

Three months ended	NPC		SPPC		SPPC		SPPC		NVE			NVE
September 30, 2009	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	933,520	$	265,734	$	19,745	$	285,479	$	8		$	1,219,007

Energy Costs:
Fuel for power generation		160,960		89,125		-		89,125		-			250,085
Purchased power		288,248		25,580		-		25,580		-			313,828
Gas purchased for resale		-		-		11,269		11,269		-			11,269
Deferred energy costs - net		46,911		26,646		2,286		28,932		-			75,843
		496,119		141,351		13,555		154,906		-			651,025

Gross Margin	$	437,401	$	124,383	$	6,190	$	130,573	$	8		$	567,982

Other		68,521						38,843		628			107,992
Maintenance		12,014						8,173		-			20,187
Depreciation and amortization		54,996						27,545		-			82,541
Taxes:
Income taxes (benefit)		75,214						10,445		(4,879	)		80,780
Other than income		8,970						6,162		45			15,177

Operating Income	$	217,686					$	39,405	$	4,214		$	261,305

Nine months ended	NPC		SPPC		SPPC		SPPC		NVE			NVE
September 30, 2009	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	1,945,818	$	734,386	$	132,686	$	867,072	$	25		$	2,812,915

Energy Costs:
Fuel for power generation		455,355		229,119		-		229,119		-			684,474
Purchased power		541,746		92,439		-		92,439		-			634,185
Gas purchased for resale		-		-		101,457		101,457		-			101,457
Deferred energy costs - net		144,910		68,222		1,923		70,145		-			215,055
		1,142,011		389,780		103,380		493,160		-			1,635,171

Gross Margin	$	803,807	$	344,606	$	29,306	$	373,912	$	25		$	1,177,744

Other		206,771						123,748		2,036			332,555
Maintenance		58,280						23,939		-			82,219
Depreciation and amortization		160,869						80,043		-			240,912
Taxes:
Income taxes (benefit)		57,702						24,275		(10,769	)		71,208
Other than income		26,394						17,046		137			43,577

Operating Income	$	293,791					$	104,861	$	8,621		$	407,273

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Three Months Ended	NPC			SPPC			SPPC			SPPC			NVE			NVE
September 30, 2008	Electric			Electric			Gas			Total			Other			Consolidated

Operating Revenues	$	826,825		$	271,919		$	19,379		$	291,298		$	8		$	1,118,131

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

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


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

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

Nine Months Ended	NPC			SPPC			SPPC			SPPC			NVE			NVE
September 30, 2008	Electric			Electric			Gas			Total			Other			Consolidated

Operating Revenues	$	1,866,220		$	758,612		$	137,125		$	895,737		$	19		$	2,761,976

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

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


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

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

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NOTE 3. REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions of Notes to Financial Statements in NPC’s and SPPC’s 2008 Form 10-K, for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):

Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance authorized in 2009 DEAA	$	74,885	(1)	$	(24,870	)	$	(8,733	)	$	41,282
2009 Amortization		111			286			-			397
2009 Deferred Energy Costs (Over Collections) (2)		(110,304	)		(68,777	)		(2,327	)		(181,408	)
Nevada Deferred Energy Balance at September 30, 2009 - Subtotal	$	(35,308)		$	(93,361	)	$	(11,060	)	$	(139,729	)
Cumulative CPUC balance		-			1,098			-			1,098
Western Energy Crisis Rate Case (effective 6/07, 3 years)		21,543			-			-			21,543
Reinstatement of deferred energy (effective 6/07, 10 years)		150,571			-			-			150,571

Total	$	136,806		$	(92,263	)	$	(11,060	)	$	33,483

Current Assets
Other deferred charges (3)		-			1,098			-			1,098
Deferred Assets
Deferred energy costs		141,568			-			-			141,568
Current Liabilities
Deferred energy costs		(4,762	)		(93,361	)		(11,060	)		(109,183	)
Total	$	136,806		$	(92,263	)	$	(11,060	)	$	33,483

(1)	These deferred costs include PUCN ordered adjustments and will be included as an offset to 2009 Deferred Energy Over-Collections within the February 2010 DEAA filings.
(2)	These deferred costs (over collections) are to be requested in February 2010 DEAA filings, and include PUCN ordered adjustments.
(3)	Refer to Note 12, Assets Held For Sale.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Ely Energy Center

On February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $76.6 million as of September 30, 2009. Management expects full recovery of the amounts expended through September 30, 2009. Future plans with respect to the EEC will be addressed through the Utilities’ IRP processes. In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC. Simultaneously, the Utilities filed a new UEPA application for the construction of the ON Line project.

Nevada Power Company

NPC 2009 Nevada IRP

In July 2009, as required by Nevada law, NPC filed its 2009 triennial IRP with the PUCN. As a result of reviews of the Company’s load forecast by the PUCN and NPC, NPC requested to withdraw its July 2009 IRP. On August 3, 2009, the PUCN approved NPC’s withdrawal request and agreed that NPC met its statutory deadline for filing, contingent upon refiling its triennial IRP no later than December 1, 2009.

Sierra Pacific Power Company

SPPC California Divestiture Filing

In October 2009, SPPC and CalPeco filed an application with the CPUC requesting approval of the transaction in which SPPC has agreed to sell its California electric distribution and generation assets to CalPeco. Upon closing of the transaction, SPPC will transfer to CalPeco all of its California electric distribution and generation assets and approximately 46,000 retail electric customers. Separately, SPPC will file an application with the PUCN requesting PUCN approval of the transaction. See Note 12, Assets Held for Sale.

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SPPC California GRC

In July 2008, SPPC filed a GRC with the CPUC and subsequently filed an amendment to the original filing in December 2008. SPPC requested an ROE of 11.4% and ROR of 8.81% and an increase in general revenues of $8.9 million. In July 2009 a settlement was filed with the CPUC, which includes the following:

•		Increase in general rates of $5.5 million, approximately an 8% increase;
•		ROE and ROR of 10.7% and 8.51%, respectively;
•		Approval of authorization to recover the costs of major plant additions, which include the Tracy Generating Station, and distribution plant additions, as well as a decrease to the California Energy Efficiency Program; and
•		Approval of a two-part mechanism to recover changes in non-energy cost adjustment clause costs incurred during the two years between rate cases.

SPPC cannot predict when the CPUC will rule on the matter, but expects rates to be effective shortly after a final order is issued.

Settled Regulatory Actions

Nevada Power Company

NPC 2009 DEAA

In February 2009, NPC filed an application to create a new DEAA rate. In this application, NPC requested to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs. In its order issued in September 2009, the PUCN ordered that the DEAA rate remain set at $0.00 per kWh, a slight increase to the Temporary Renewable Energy Development charge and slight decrease to the Renewable Energy Program Rate which is a decrease to revenues of $4.6 million, or a 0.20% decrease. The PUCN found that NPC’s purchases of fuel and power were prudent and approved those costs for the test period which will be included as an offset to 2009 deferred energy over-collections within the February 2010 DEAA filing.

NPC 2008 GRC

In December 2008, NPC filed its statutorily required GRC with the PUCN and further updated the filing in February and March 2009. The filing, as updated, requested an ROE of 11.0% and ROR of 8.88% and an increase to general revenues of $305.7 million.

The PUCN issued its order in June 2009, which resulted in the following significant items:

•		Increase in general rates by $222.7 million, approximately a 9.8% increase;
•		ROE and ROR of 10.5% and 8.53%, respectively;
•		Authorized to recover the costs of major plant additions including the purchase of the Higgins Generating Station, construction of Clark Peaking Units, an upgrade to the emission control systems on existing units at the Clark Generating Station, installation of environmental equipment upgrades at the Reid Gardner Generating Station and new transmission and distribution projects;
•		CWIP as of November 2008 in rate base for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen site; and
•		A two phase implementation of the rate increase. The Phase I increase is effective July 1, 2009 and results in a 3% increase to all core customer classes. The Phase II increase is effective January 1, 2010 and implements the remainder of the increase to all core customer classes. The PUCN granted approval for NPC to track and record the cost of the phased-in increases each month in a regulatory asset account and permitted NPC to record a carrying charge on these amounts. NPC will seek authority to amortize this regulatory asset in its next GRC filing, currently scheduled for June 2011.

Mohave Generating Station

In June 2009, majority stakeholder Southern California Edison announced that the Mohave Generating Station, owned 14% by NPC, will be dismantled and its operating permits terminated following a December 2005 suspension of operations due to pending environmental matters. As discussed in the 2008 Form 10-K, the net book value of the Mohave Generating Station is included in Other Regulatory Assets and any costs or savings related to the Mohave Generating Station are accumulated in Other Regulatory Assets. NPC believes it will continue to recover the costs for the Mohave Generating Station through the regulatory process and does not expect the dismantling of the plant to have a material impact on its financial condition.

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Sierra Pacific Power Company

SPPC Nevada Gas DEAA

In February 2009, SPPC filed an application to create a new gas DEAA rate for Nevada customers. In this application, SPPC requested to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs. The PUCN issued its order in September 2009 approving SPPC’s requested rate decrease and approving SPPC’s purchases of natural gas and propane as prudent for the test period. The new DEAA rate became effective October 1, 2009.

SPPC Nevada Electric DEAA

In February 2009, SPPC filed an application to create a new electric DEAA rate for Nevada customers. In this application, SPPC requested to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs. The PUCN issued its order in September 2009 decreasing rates by $30.8 million, a decrease of 3.19% and approving SPPC’s purchases of fuel and power as prudent for the test period. The new credit DEAA rate became effective October 1, 2009.

NOTE 4. LONG-TERM DEBT

As of September 30, 2009, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

	NPC			SPPC		NVE Holding Co. and Other Subs.		NVE Consolidated
2009	$	(84	)	$	-	$	-	$	(84	)
2010		116,004			-		-		116,004
2011		369,924			-		-		369,924
2012		136,449			100,000		63,670		300,119
2013		7,146			250,000		-		257,146
		629,439			350,000		63,670		1,043,109
Thereafter		3,093,359			993,500		421,539		4,508,398
		3,722,798			1,343,500		485,209		5,551,507
Unamortized Premium (Discount) Amount		(12,204	)		18,502		533		6,831
Total	$	3,710,594		$	1,362,002	$	485,742	$	5,558,338

Substantially all utility plant is subject to the liens of NPC’s and SPPC’s Indentures under which their respective General and Refunding Mortgage securities are issued.

Nevada Power Company

Tender Offer

On October 7, 2009, NPC settled its cash tender offer, which commenced on September 8, 2009 and expired on October 5, 2009 for the following securities:

•		Clark County, Nevada Industrial Development Refunding Revenue Bonds (Nevada Power Company Project) Series 2000A, in an aggregate principal amount of $100 million;
•		Coconino County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2006A, in an aggregate principal amount of $40 million; and
•		Clark County, Nevada Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2006, in an aggregate principal amount of $39.5 million (collectively, “the NPC Bonds”).

Those holders who tendered their NPC Bonds by the expiration date were entitled to receive a purchase price of $900 per $1,000 NPC Bond, plus any accrued and unpaid interest to, but not including, the date that is two business days following the October 5, 2009 expiration date. Approximately $5.7 million of the $179.5 million NPC Bonds outstanding were validly tendered and accepted by NPC. NPC financed the tendered bonds with available cash. The tendered NPC Bonds remain outstanding and have not been retired or cancelled. However, as NPC is the sole holder of the NPC Bonds, for financial reporting purposes the investment in the tendered NPC Bonds and the indebtedness will be offset for presentation purposes.

Maturity of Clark County Nevada Pollution Control Revenue Bonds, Series 2000B

On October 1, 2009 the Clark County Nevada Pollution Control Revenue Bonds, Series 2000B, in the aggregate principal amount of $15 million, matured. In July 2008, these securities were converted from auction rate securities to variable rate demand notes. As further disclosed in Note 6, Long-Term Debt in the 2008 Form 10-K, NPC purchased 100% of the bonds at that time, and remained the sole holder of these bonds until the maturity date. NPC financed the maturity with available cash.

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Revolving Credit Facilities

On March 2, 2009, NPC amended its $600 million Second Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $589 million.

On January 5, 2009, NPC entered into a new $90 million supplemental revolving credit facility. The facility has a term of 364 days, and is secured by General and Refunding Mortgage bonds. This credit facility matures in January 2010, and is in addition to NPC’s existing approximate $589 million revolving credit facility.

General and Refunding Mortgage Notes, Series V

On March 2, 2009, NPC issued and sold $500 million of its 7.125% General and Refunding Mortgage Notes, Series V due 2019. The net proceeds of the issuance were used to repay approximately $404 million of amounts outstanding under NPC’s approximate $589 million revolving credit facility and for general corporate purposes.

General and Refunding Mortgage Notes, Series U

On January 12, 2009, NPC issued and sold $125 million of its 7.375% General and Refunding Mortgage Notes, Series U due 2014. The net proceeds of the issuance were used to repay approximately $124 million of amounts outstanding under NPC’s approximate $589 million revolving credit facility.

Sierra Pacific Power Company

Tender Offer

On October 7, 2009, SPPC settled its cash tender offer, which commenced on September 8, 2009 and expired on October 5, 2009 for the following securities:

•		Washoe County, Nevada Gas Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A, in an aggregate principal amount of $58.7 million;
•		Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B, in an aggregate principal amount of $75 million; and
•		Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C, in an aggregate principal amount of $84.8 million (collectively, “the SPPC Bonds”).

Those holders who tendered their SPPC Bonds by the expiration date were entitled to receive a purchase price of $900 per $1,000 SPPC Bond, plus any accrued and unpaid interest to, but not including, the date that is two business days following the October 5, 2009 expiration date. Approximately $3.8 million of the $218.5 million SPPC Bonds outstanding were validly tendered and accepted by SPPC. SPPC financed the tendered bonds with available cash. The tendered SPPC Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the SPPC Bonds, for financial reporting purposes the investment in the tendered SPPC Bonds and the indebtedness will be offset for presentation purposes.

General and Refunding Mortgage Notes, Series M

On August 21, 2009, SPPC issued an additional $150 million in aggregate principal amount of its 6% General and Refunding Mortgage Notes, Series M, as part of the same series as the original Series M Notes issued in March 2006. Upon the issuance of these Notes, the aggregate principal amount of the Series M Notes outstanding is $450 million. The proceeds from the second issuance were used to repay amounts outstanding under SPPC’s revolving credit facility.

Revolving Credit Facility

On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $332 million.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

On January 14, 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness is offset for presentation purposes.

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NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The September 30, 2009 carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments.

The total fair value of NVE’s consolidated long-term debt at September 30, 2009, is estimated to be $5.9 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $4.9 billion as of December 31, 2008.

The total fair value of NPC’s consolidated long-term debt at September 30, 2009, is estimated to be $4.0 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $3.1 billion at December 31, 2008.

The total fair value of SPPC’s consolidated long-term debt at September 30, 2009, is estimated to be $1.4 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.3 billion as of December 31, 2008.

NOTE 6. DERIVATIVES AND HEDGING ACTIVITIES

NVE, SPPC and NPC apply the accounting guidance as required by the Derivatives and Hedging Topic of the FASC. The accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities, 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. The accounting guidance for derivative instruments also provides a scope exception for commodity contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value.

Interest Rate Risk

In August 2009, NPC entered into two interest rate swap agreements which terminate in 2011, for an aggregated notional amount of $350 million associated with its $350 million 8.25% General and Refunding Mortgage Notes, Series A, due 2011. The interest rate swaps manage the existing fixed rate interest rate exposure with a variable interest rate in order to lower overall borrowing costs. As allowed by the Regulated Operations Topic of the FASC, as of September 30, 2009, the fair value of the interest rate swaps were recorded as a Risk Management Asset with the corresponding offset recorded as a Risk Management Regulatory Liability and are included in the fair value table below.

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. NVE and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities’ to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

Credit Risk Contingent Features

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s, Fitch, and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities’ Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of September 30, 2009, the maximum amount of collateral NPC and SPPC would be required to post under these agreements is approximately $66.3 million and $42.9 million, respectively, based on mark-to-market liability values, which are substantially based on quoted market prices. Of this amount, approximately $51.1 million and $32.9 million, respectively, would be required if the Senior Unsecured debt ratings of NPC and SPPC are downgraded one level and additional amounts of approximately $15.2 million and $10.0 million would be required, respectively, if the Senior Unsecured debt ratings of NPC and SPPC are downgraded two levels.

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Determination of Fair Value

As required by the Fair Value Measurements and Disclosure Topic of the FASC, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps, options and interest rate swaps. Total risk management assets below do not include option premiums on commodity contracts which are not considered a derivative asset. Option premiums upon settlement are recorded in fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism. Option premium amounts included in risk management assets for NVE, NPC and SPPC were as follows (dollars in millions):

	Option Premiums
	September 30, 2009						December 31, 2008
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	12.3	$	9.3	$	3.0	$	13.3	$	9.7	$	3.6
Non-Current		3.3		2.4		0.9		5.6		4.2		1.4
Total	$	15.6	$	11.7	$	3.9	$	18.9	$	13.9	$	5.0

Forwards and swaps are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Options are valued based on an income approach using an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option volatility rates. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative instruments not only includes counterparty risk, but also the impact of NVE and the Utilities nonperformance risk on their liabilities. Nonperformance risk is based on the credit quality of NVE and the Utilities and had an immaterial impact to the fair value of their derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the consolidated balance sheets of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria as required by the Derivatives and Hedging Topic of the FASC. Additionally, as required by the Regulated Operations Topic of the FASC, regulatory assets and liabilities are established to the extent that 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 derivative transactions until the period of settlement and to not recognize gains and losses through income (dollars in millions):

	September 30, 2009									December 31, 2008
	Fair Value									Fair Value
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC
Risk management assets - current	$	17.9		$	14.5		$	3.4		$	2.8		$	2.0		$	0.8
Risk management assets - non-current (1)		18.3			14.6			3.7			4.4			3.2			1.2
Total risk management assets		36.2			29.1			7.1			7.2			5.2			2.0

Risk management liabilities - current		109.1			65.9			43.2			313.8			222.9			90.9
Risk management liabilities - non-current		1.1			0.5			0.6			53.4			35.2			18.2
Total risk management liabilities		110.2			66.4			43.8			367.2			258.1			109.1

Total risk management regulatory assets/liabilities – net (2)	$	(74.0	)	$	(37.3	)	$	(36.7	)	$	(360.0	)	$	(252.9	)	$	(107.1	)

(1)

Included in Risk management assets – non-current is a $2.7 million gain for interest rate swaps, as discussed above, with the offset recorded in the risk management regulatory assets/liabilities amounts above.

(2)

When amount is negative it represents a Risk Management Regulatory Asset, when positive it represents a Risk Management Regulatory Liability. NVE, NPC, and SPPC would have recorded gains for the three months ended September 30, 2009 of $236.6 million, $185.2 million, and $51.4 million, respectively, and for the nine months ended September 30, 2009, NVE, NPC and SPPC, would have recorded gains of $286.0 million, $215.6 million and $70.4 million, respectively. However, as required by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains and losses, which are included in the Risk Management Regulatory Assets/Liabilities amounts above.

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 their counterparties and the changes in market prices. Risk management assets as of September 30, 2009, increased primarily due to lower contract prices as compared to December 31, 2008. Risk management liabilities decreased as of September 30, 2009, as compared to December 31, 2008, primarily due to increased settlements of derivative contracts during the three month period ending September 30, 2009, which is the Utilities’ peak season.

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The following table shows the commodity volume for our open derivative contracts related to natural gas contracts (amounts in millions):

	September 30, 2009 Commodity Volume (MMBTU)						December 31, 2008 Commodity Volume (MMBTU)
	NVE		NPC		SPPC		NVE		NPC		SPPC

Commodity volume assets - current		31.9		26.0		5.9		1.2		1.0		0.2
Commodity volume assets - non-current		29.1		21.3		7.8		1.1		1.0		0.1
Total commodity volume of assets		61.0		47.3		13.7		2.3		2.0		0.3

Commodity volume liabilities - current		78.0		54.8		23.2		119.9		86.7		33.2
Commodity volume liabilities - non-current		1.1		0.6		0.5		40.6		28.6		12.0
Total commodity volume of liabilities		79.1		55.4		23.7		160.5		115.3		45.2

NOTE 7. COMMITMENTS AND CONTINGENCIES

Environmental Contingencies

Nevada Power Company

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.

Sierra Pacific Power Company

Valmy Generating Station

On June 22, 2009, SPPC received a request for information from the EPA—Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada. SPPC co-owns and operates this coal-fired plant. Idaho Power Company owns the remaining 50%. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the EPA relating to the plant. SPPC is currently preparing its response to the EPA and will continue to monitor developments relating to this Section 114 request. It is anticipated that the initial response will be complete in the fourth quarter of 2009, and as of September 30, 2009, SPPC cannot predict the impact, if any, associated with this information request.

Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As disclosed in Note 13, Commitments and Contingencies of the Notes to Financial Statements, Environmental, in the 2008 Form 10-K, NPC was subject to various environmental proceedings which were settled as of December 31, 2008. NPC continues to comply with these environmental commitments. As of September 30, 2009, environmental expenditures did not change materially from those disclosed in the 2008 Form 10-K.

Litigation Contingencies

Nevada Power Company

Lawsuit Against Natural Gas Providers

In April 2003, NVE (originally filed under the corporate name of SPR) and NPC filed a complaint in the U.S. District Court for the District of Nevada (“District Court”) against several natural gas providers and traders. In July 2003, NVE 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 (“El Paso”); (2) Dynegy Marketing and Trade (“Dynegy”); and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric (collectively, “Sempra”). On December 13, 2005, the District Court dismissed NVE and NPC’s claims. NVE and NPC appealed this decision to the Ninth Circuit. Subsequently, NVE abandoned its appeal and the matter proceeded only with respect to NPC. In September 2007, the Ninth Circuit reversed the District Court’s order. In November 2007, the Ninth Circuit denied the gas providers and traders’ petition for rehearing. The Ninth Circuit has remanded the case to the District Court for further proceedings. In January 2008, the defendants filed motions to dismiss, to which NPC responded in February 2008. In June 2008, NPC’s claims survived the defendant’s filed motions to dismiss. On December 9, 2008, NPC settled with Sempra for an immaterial amount. In June 2009, NPC reached settlement agreements with both El Paso and Dynegy. Any disputes previously existing between the parties have now been resolved and all claims have been dismissed.

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Peabody Western Coal Company

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

Royalty Claim

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

The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners. NPC believes Peabody WC’s claims are without merit. In July 2008, the Court dismissed all counts against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo and Mohave Generating Stations. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo and Mohave Generating Stations by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action was stayed from October 2004 until March 2008 pending resolution of discovery related motions. Those discovery motions have now been resolved and the Court ordered completion of factual discovery by February 11, 2010. Factual discovery is ongoing.

Sierra Pacific Power Company

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to TMWA in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA or SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the Farad flume and Farad Dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada (“District Court”) on a coverage dispute relating to potential rebuild costs for Farad Dam. The case went to trial before the District Court in April 2008. On September 30, 2008, the District Court ruled that SPPC was not time barred from reconstructing Farad Dam, and has coverage for the full rebuild costs, subject to coverage sub-limits set forth in the insurance policies. The District Court further ruled that SPPC is entitled to recover $4 million for costs incurred to date on Farad Dam and that SPPC shall have three years to rebuild the dam from September 30, 2008. In the event Farad Dam is not rebuilt, the District Court determined SPPC would be entitled to actual cash value of approximately $1.3 million. SPPC requested the District Court to reconsider the cash value to reflect rebuild costs. On July 10, 2009, the District Court declined SPPC’s request and further ordered that the three year period to replace the dam now commences as of July 10, 2009. In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court). Subsequently, in mid August 2009, the Insurers appealed the District Court’s Coverage Decision with the Ninth Circuit Court. In September 2009, the Ninth Circuit Court ordered the parties to complete briefing on both appeals by early March 2010.

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Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal matters, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.

NOTE 8. EARNINGS PER SHARE (NVE)

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

	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
Basic EPS
Numerator ($000)

Net income	$	182,646	$	150,783	$	178,785	$	210,975

Denominator
Weighted average number of common shares outstanding		234,629,761		234,096,559		234,479,605		233,975,552

Per Share Amounts

Net income per share - basic	$	0.78	$	0.64	$	0.76	$	0.90

Diluted EPS
Numerator ($000)

Net income	$	182,646	$	150,783	$	178,785	$	210,975

Denominator (1)
Weighted average number of shares outstanding before dilution		234,629,761		234,096,559		234,479,605		233,975,552
Stock options		37,132		26,738		23,983		48,340
Non-Employee Director stock plan		104,609		66,130		94,900		59,810
Employee stock purchase plan		10,058		-		8,247		290
Restricted Shares		13,307		11,804		9,542		6,121
Performance Shares		574,052		453,901		409,277		409,156
		235,368,919		234,655,132		235,025,554		234,499,269

Per Share Amounts

Net income per share - diluted	$	0.78	$	0.64	$	0.76	$	0.90

(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, 2009 and 2008, due to conversion prices being higher than market prices for all periods. Under this plan for the three and nine months ended September 30, 2009, 731,505 and 850,596 shares, respectively, would be included and 1,049,833 and 977,463 shares, respectively, would be included for the three and nine months ended September 30, 2008, if the conditions for conversions were met.

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NOTE 9. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other postretirement costs for the three and nine months ended September 30 follows. This summary is based on a December 31, 2008 measurement date for 2009 and a September 30, 2007 measurement date for 2008 (dollars in thousands):

NV Energy, Inc., Consolidated

	Pension Benefits						Other Postretirement Benefits
	For the Three Months Ended September 30,						For the Three Months Ended September 30,
	2009			2008			2009			2008

Service cost	$	4,709		$	5,237		$	577		$	641
Interest cost		11,036			10,677			2,637			2,683
Expected return on plan assets		(9,290	)		(11,463	)		(1,508	)		(2,088	)
Amortization of prior service cost		(448	)		(265	)		(171	)		(257	)
Amortization of net loss		6,894			1,980			1,273			872
Settlement loss		-			-			84			-

Net periodic benefit cost	$	12,901		$	6,166		$	2,892		$	1,851


	Pension Benefits						Other Postretirement Benefits
	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
		2009			2008			2009			2008

Service cost	$	14,128		$	16,506		$	1,732		$	1,922
Interest cost		33,109			32,142			7,912			8,049
Expected return on plan assets		(27,870	)		(35,587	)		(4,525	)		(6,264	)
Amortization of prior service cost		(1,345	)		25			(514	)		(771	)
Amortization of net loss		20,681			4,733			3,818			2,617
Settlement loss		-			-			254			-

Net periodic benefit cost	$	38,703		$	17,819		$	8,677		$	5,553

Nevada Power Company

	Pension Benefits						Other Postretirement Benefits
	For the Three Months Ended September 30,						For the Three Months Ended September 30,
	2009			2008			2009			2008

Service cost	$	2,393		$	3,103		$	310		$	304
Interest cost		5,270			5,334			607			631
Expected return on plan assets		(4,462	)		(5,496	)		(509	)		(675	)
Amortization of prior service cost		(433	)		(205	)		289			289
Amortization of net loss		3,298			983			287			202
Settlement loss		-			-			19			-

Net periodic benefit cost	$	6,066		$	3,719		$	1,003		$	751


	Pension Benefits						Other Postretirement Benefits
	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
		2009			2008			2009			2008

Service cost	$	7,179		$	9,715		$	931		$	912
Interest cost		15,809			15,944			1,820			1,893
Expected return on plan assets		(13,385	)		(17,058	)		(1,528	)		(2,026	)
Amortization of prior service cost		(1,300	)		159			868			868
Amortization of net loss		9,894			2,339			861			606
Settlement loss		-			-			57			-

Net periodic benefit cost	$	18,197		$	11,099		$	3,009		$	2,253

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Sierra Pacific Power Company

	Pension Benefits						Other Postretirement Benefits
	For the Three Months Ended September 30,						For the Three Months Ended September 30,
	2009			2008			2009			2008

Service cost	$	2,061		$	1,940		$	251		$	319
Interest cost		5,471			5,045			2,014			2,013
Expected return on plan assets		(4,580	)		(5,668	)		(977	)		(1,378	)
Amortization of prior service cost		(26	)		(62	)		(465	)		(550	)
Amortization of net loss		3,425			913			978			658
Settlement loss		-			-			65			-

Net periodic benefit cost	$	6,351		$	2,168		$	1,866		$	1,062


	Pension Benefits						Other Postretirement Benefits
	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
		2009			2008			2009			2008

Service cost	$	6,184		$	6,058		$	755		$	956
Interest cost		16,414			15,194			6,041			6,041
Expected return on plan assets		(13,741	)		(17,601	)		(2,932	)		(4,134	)
Amortization of prior service cost		(78	)		(74	)		(1,394	)		(1,651	)
Amortization of net loss		10,276			2,168			2,934			1,975
Settlement loss		-			-			195			-

Net periodic benefit cost	$	19,055		$	5,745		$	5,599		$	3,187

On September 30, 2009, NVE notified retirees that it was capping contributions for retiree medical plans at 2009 levels in order to contain costs. The revaluation resulting from these changes has resulted in a reduction to the liability for other postretirement benefits of $24.2 million at September 30, 2009.

In 2008, as required by the Compensation Retirement Benefits Topic of the FASC, NVE, NPC and SPPC recorded additional pension costs relating to the elimination of the early measurement date to retained earnings of $5.3 million, $3.6 million and $1.4 million, respectively, before taxes. Also, in 2008, in accordance with the accounting guidance, NVE, NPC and SPPC recorded additional post retirement benefit costs relating to the elimination of the early measurement date, to retained earnings of $1.0 million, $0.6 million and $0.4 million, respectively, before taxes. These amounts represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007.

For the nine months ended September 30, 2009, the companies made contributions to the pension plan totaling $60 million, with $25.5 million allocated to the 2008 plan year and the remainder to the 2009 plan year. At the present time it is anticipated that there will be further contributions made to the pension and other postretirement benefits plans in 2009, however the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution.

NOTE 10. DIVIDENDS

On February 5, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share which was paid in March 2009 to common shareholders of record on March 3, 2009. On April 30, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share to common shareholders of record on June 2, 2009, which was paid on June 17, 2009. On August 6, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share to common shareholders of record on September 1, 2009, which was paid on September 16, 2009.

As of September 30, 2009, NVE contributed capital to SPPC of $90.3 million.

During the nine months ended September 30, 2009, NPC and SPPC paid dividends to NVE of $69.5 million and $128.8 million, respectively. On October 19, 2009, NPC paid dividends to NVE of $7.5 million.

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NOTE 11. INCOME TAXES

On or about December 31, 2007, NVE and the Utilities filed a Form 3115, Application for Change in Accounting Method (“Application”), with the IRS requesting a change in accounting for deducting repair expenditures. NVE reflected the tax benefits sought on the Application on its 2007 tax return, which was filed during 2008, thus yielding an increase in uncertain tax benefits related to prior periods.

In April 2009, NVE and the Utilities received notice from the IRS approving the Application. Accordingly, during the second quarter of 2009, NVE, NPC and SPPC recorded reductions to their unrecognized tax benefits for the repair positions taken in the prior period of approximately $55.5 million, $32.0 million, and $32.3 million, respectively.

NOTE 12. ASSETS HELD FOR SALE

In April 2009, SPPC entered into an agreement to sell its California electric distribution and generation assets to CalPeco. Based on the terms of the purchase agreement, SPPC will receive proceeds that include a premium on current net rate base assets as of the closing date, plus a working capital adjustment. Net rate base assets include utility plant in service, net and deferred credits and other liabilities. Such proceeds are expected to be above the current book value of the related net assets. The sale is expected to close in 2010, and is subject to obtaining necessary federal and state regulatory approvals.

Below are the major classes of assets and liabilities held for sale and presented in the consolidated balance sheets as of September 30, 2009 and December 31, 2008 (dollars in millions):

Assets	September 30, 2009		December 31, 2008

Utility Plant in Service	$	179.6	$	183.2

Less: Accumulated depreciation		53.3		56.0
Utility Plant in Service, net		126.3		127.2

CWIP		7.3		5.5
Other current assets		5.3		6.8
Deferred Charges		2.0		3.0

Assets Held for Sale	$	140.9	$	142.5

Liabilities

Deferred Credits and Other Liabilities	$	29.9	$	24.1

Liabilities Held for Sale	$	29.9	$	24.1

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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 NVE, NPC or SPPC; (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)

economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, weaker housing markets, a decrease in tourism, particularly in southern Nevada, and cancelled or deferred hotel construction projects, each of which affect customer collections, customer demand and usage patterns;

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

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

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

(5)

the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of: continued volatility in the global credit markets, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN, untimely regulatory approval for utility financings, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

(6)

employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, the ability to adjust the labor cost structure to changes in growth within our service territories, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce;

(7)

unseasonable weather, drought, threat of wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability to procure adequate supplies of fuel or purchased power, and the cost of procuring such supplies could affect the amount of water available for electric generating plants in the Southwestern U.S., and could have other adverse effects on our business;

(8)

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), physical availability, sharp increases in the prices for fuel (including increases in long term transportation costs) and/or power, or a ratings downgrade;

(9)

wholesale market conditions, including availability of power on the spot market and the availability to enter into gas financial hedges with creditworthy counterparties, which affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

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

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

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(12)

unfavorable or untimely rulings in rate or other 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;

(13)

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

(14)

the discretion of NVE's BOD regarding NVE's future common stock dividends based on the BOD 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 NVE's and the Utilities' agreements;

(15)	the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;

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

(17)	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;

(18)

changes in the business or power demands of the Utilities’ major customers, including those engaged in gold mining or gaming, which may result in changes in the demand for services of the Utilities, including the effect on the Nevada gaming industry of the opening of additional gaming establishments in California, other states and internationally; and

(19)	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. NVE, 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.

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;
•	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
•	may apply standards of materiality in a way that is different from what may be viewed as material to investors; and
•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

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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 NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes the following:

●	For each of NVE, NPC and SPPC:

	§	Results of Operations
	§	Analysis of Cash Flows
	§	Liquidity and Capital Resources

●	Regulatory Proceedings (Utilities)

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

NVE recognized net income of $182.6 million for the three months ended September 30, 2009 compared to net income of $150.8 million for the same period in 2008. For the nine months ended September 30, 2009 NVE recognized net income of $178.8 million compared to $211.0 million for the same period in the prior year. Consolidated gross margin increased by $89.5 million and $118.8 million for the three months and nine months ended, respectively, primarily due to increased rates as a result of NPC’s 2008 GRC, effective July 1, 2009 in the case of the three months, and SPPC’s 2007 GRC effective July 1, 2008 in the case of the nine months. Consolidated net income increased for the three months ended September 30, 2009, compared to the same period in 2008 primarily due to NPC’s 2008 GRC partially offset by increased depreciation expense at the Utilities. Earnings decreased for the nine months ended September 30, 2009 compared to the same period in 2008 primarily due to increased other operating and maintenance expenses, depreciation and interest charges, some of which are costs related to the purchase of the Higgins Generating Station and the construction of the Clark Peaking Units, which were not included in rates prior to July 1, 2009 partially offset by higher revenues. Other Income/Expense items which contributed to the change in earnings are discussed in NPC’s and SPPC’s respective Results of Operations for more details on the change in earnings.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The Utilities did not reach their system peaks as forecasted; however, NPC’s 2009 system peak exceeded its 2008 system peak. The variations in energy usage by the Utilities’ customers due to varying weather and other energy usage patterns necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2009 Current Matters

The economy in Nevada has been adversely affected by the recession facing the U.S. and the global economy, resulting in decelerated customer growth compared to prior years when Nevada was experiencing high customer growth. Tourism and gaming remain southern Nevada’s leading industries, driving construction activity, the housing market and employment in the region, and together comprising one of NPC’s largest classes of customers. Management continues to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas. The hotel/motel occupancy rate has decreased approximately 6.9% as of August 2009 from a year ago. The expected room growth rate for 2009 is 6.2%, concentrated primarily in Project City Center, which is developed and jointly owned by MGM Mirage, and 4.9% for 2010. Gaming properties in southern Nevada are experiencing financial problems, including difficulties meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases. The unemployment rate in Nevada continues to increase. As of September 2009, the unemployment rate was 13.3%, compared to 7.3% in 2008. In Southern Nevada, construction activity, another leading indicator, has seen a decrease in the number of residential permits, declining 51.5% in September 2009 compared to September 2008. Furthermore, construction employment has decreased 28% as of September 2009, compared to September 2008. Other economic conditions affecting Nevada include the national decrease in real estate market activity which makes it more difficult for individuals and businesses to sell their properties in order to relocate to Nevada. These factors, among other items, are considered and evaluated by management in assessing load forecast.

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As the Utilities’ service territories transition from a time of high growth to a much slower growth rate, management continues to place a significant emphasis on modifying our business strategies to reflect the foregoing economic indicators and their effect on various factors including, but not limited to:

•		customer growth;
•		load factors;
•		future capital projects and capital requirements;
•		managing operating and maintenance expenses within projected revenue growth;
•		our liquidity and ability to access capital markets;
•		collections on accounts receivable;
•		counterparty risk; and
•		workforce reduction.

Upon evaluation of the factors above, NVE and the Utilities have reduced estimated cash requirements, as reported in the 2008 Form 10-K, for capital expenditures by approximately $145 million to $170 million for 2009 for total estimated cash requirements of $775 million to $750 million for the current year. Additionally, in 2010, the Utilities intend to reduce capital expenditures to $600 million. Furthermore, NVE and the Utilities are implementing and evaluating various labor cost strategies in an effort to manage operating costs within our projected growth. The implementation of these labor cost strategies will negatively impact results of operations in the fourth quarter of 2009. The current recessionary environment, as well as recent volatility in the global credit and financial markets, has created an unprecedented level of uncertainty regarding future business conditions. While management expects to maintain this process of continual re-evaluation for the foreseeable future, it is not possible to predict how long the impacts of the economic recession will continue or what its long-term effect will be on the economy in general or on our financial position, cash flows or results of operations in particular.

2009 and Beyond

In 2009 and beyond, management will remain focused on implementing the three part strategy of the energy supply plan which includes energy efficiency and conservation programs, purchase and development of renewable energy projects and expansion of traditional generating capacity and transmission capability to move energy throughout the state. Additional key objectives include management of energy risk, management of environmental matters, management of regulatory filings and further broadening access to capital.

Energy Efficiency and Conservation Programs

A part of our strategy to reduce dependence on purchased power is to manage our resources against our load requirements with energy efficiency and conservation programs, also known as DSM programs. NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public and low income).

As of September 30, 2009, NPC and SPPC have spent $35 million and $6.5 million, respectively in DSM programs. The final amount will be determined by numerous factors, such as the economy, the impact of federal government stimulus legislation, performance of existing and new programs and many other factors.

Purchase and Development of Renewable Energy Projects

The Utilities have embarked on a strategy to invest in renewable energy that, along with purchased power contracts and an increase in DSM programs, will enhance the opportunity for the Utilities to fully meet the Portfolio Standard as required by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewables.

In 2009 and 2010, the Utilities are required to obtain an amount of PECs equivalent to 12% of their total retail energy from renewables. In April 2009, the Utilities filed their annual compliance report for the year 2008, on the basis of which the PUCN ruled the Utilities to be in compliance with the Portfolio Standard. Additionally, recent Nevada legislation has increased the required amount of PECs from 20% to 25% beginning in the year 2020 and the solar requirement from five percent to six percent beginning in the year 2016. The Utilities continue to develop and explore sources for renewable energy. NPC’s current capital budget includes investing approximately $110 million for renewable energy projects through 2011.

Expansion of Traditional Generation

NPC continues the construction of the 500 MW (nominally rated) natural gas generating units at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011. Currently, the expansion at the Harry Allen Generating Station is the only generating project under construction. The Utilities do not anticipate any new construction or purchases of generating facilities in the near future.

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Management of Energy Risk

The Utilities have implemented a prudent strategy of piecemeal procurements transacted in regular intervals and completed before the start of the peak summer season. This provides the Utilities with ample opportunities for optimizing their portfolio on a rolling basis in anticipation of changes in system conditions, load forecasts, and regional energy market fundamentals. The Utilities also coordinate the planned maintenance schedules of their owned generating plants and transmission facilities with expectations of start dates of new generating plants or purchased power contracts.

Management of Environmental Matters

Environmental laws affect existing generating facilities and current and prospective capital construction projects. Such effects include but are not limited to increased costs, closure of existing facilities, mandated equipment upgrades, and termination of the construction of facilities. Environmental laws already affect the energy we buy; as discussed above under Purchase and Development of Renewable Energy Projects.

A key objective for the Utilities for the remainder of 2009 will be to enhance and maintain our energy infrastructure investments in ways that meet customer demand for reliable energy in an efficient and environmentally responsible manner, including but not limited to the recognition and monitoring of proposed federal legislation establishing a nationwide mandatory cap on emissions of greenhouse gases. The Utilities believe that a diverse and balanced portfolio of energy resources represents opportunity for reliability and cost control, yet are also mindful of our overriding environmental responsibility. The Utilities are committed to making technology choices with a primary focus on limiting emissions and optimizing our investments so that prices remain competitive.

Management of Regulatory Filings

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

The PUCN issued its order on NPC’s 2008 GRC in June 2009, details of the decision can be found at Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. Other pending and settled regulatory actions are discussed in more detail in Note 3, Regulatory Actions of the Notes to Financial Statements of this Form 10-Q and the 2008 Form 10-K.

Further Broaden Access to Capital

A significant focus for the remainder of 2009 will be to continue to generate sufficient cash from operations to meet operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs.

Commodity prices and the amount of capital required for construction projects are projected to be significantly lower for the remainder of 2009 compared to 2008. As a result, for the remainder of 2009, the Utilities believe they will be able to meet such financial obligations with a combination of internally generated funds and the use of the Utilities’ revolving credit facilities. However, 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 additional debt to support their operating costs or further delay capital expenditures, and NVE may need to issue additional equity securities. As such, maintaining sufficient liquidity through the use of the Utilities’ revolving credit facilities and maintaining our ability to issue new debt or equity securities at NVE on favorable terms continues to be a significant focus in 2009.

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NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $29.0 million and $31.3 million of interest costs for the nine months ended September 30, 2009 and 2008 respectively.

As of September 30, 2009 NPC had paid $69.5 million in dividends to NVE and SPPC had paid $128.8 million in dividends to NVE. Additionally, on October 19, 2009, NPC paid $7.5 million in dividends to NVE.

Other Subsidiaries

Other Subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the nine months ended September 30, 2009 compared to the same period in 2008 due to reduction in cash from financing activities and a slight increase in cash used for investing activities partially offset by an increase in cash from operating activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to the over collection of revenues in excess of fuel and purchased power costs, decreased purchased power and fuel costs, increased BTGR revenues beginning July 1, 2009 in the case of NPC and for the first six months of 2009 in the case of SPPC, and the settlement of outstanding litigation. These increases were partially offset by increased operating and maintenance costs for new generating facilities, some of which were not included in rates until July 1, 2009, higher balances for fuel and purchased power costs at year end December 31, 2008, that were subsequently paid in 2009, pension funding, increased interest costs, the receipt of prepaid transmission revenue in 2008 and the repayment of transmission deposits in 2009.

Cash Used By Investing Activities. Cash used for investing activities did not change significantly between the periods.

Cash From Financing Activities. Cash from financing activities decreased primarily due to a decrease in the issuance of long term debt, increased payments on the revolving credit facility, the reacquisition of debt and increased dividend payments to common shareholders.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’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, in the case of SPPC, 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 matters, and economic conditions.

Available Liquidity as of September 30, 2009 (in millions)
	NVE		NPC		SPPC
Cash and Cash Equivalents	$	6.2	$	30.8	$	58.4
Balance available on Revolving Credit Facility1		n/a		555.3		316.1
	$	6.2	$	586.1	$	374.5

As of October 28, 2009, NPC and SPPC had approximately $653.3 million and $316.9 million available under their revolving credit facilities, which reflects amounts oustanding under letters of credit.

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NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, the Utilities may use their revolving credit facilities in order to meet their liquidity needs. Alternatively, depending on the usage of the Utilities’ revolving credit facilities, NVE and the Utilities may issue long-term debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. NVE and the Utilities anticipate with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the Utilities’ revolving credit facilities, will be sufficient to meet short-term operating costs. However, 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, if operating costs are not recovered in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity, NVE and the Utilities may be required to further delay capital expenditures, re-finance debt or issue equity at NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

NVE and the Utilities do not have significant debt maturities in 2009 or 2010 other than their revolving credit facilities. The Utilities’ long-term credit facilities expire in November 2010, and NPC’s Supplemental Revolving Credit Facility expires in January 2010. As of October 28, 2009, NPC has borrowed approximately $10 million on its revolving credit facility and SPPC has no current borrowings outstanding.

There have been no changes to the credit ratings of NVE and the Utilities in 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

NVE (stand-alone) has approximately $2.5 million of debt service obligations remaining for 2009, which it intends to fund through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries below).

During the nine months ended September 30, 2009, there were no material changes to contractual obligations as set forth in NVE’s 2008 Form 10-K. See NPC’s and SPPC’s respective sections for changes in their contractual obligations.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of September 30, 2009, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $191.5 million of its unsecured 6.75% Senior Notes due 2017; and $230 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, NVE’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 that subsidiary’s creditors. Therefore, NVE’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, 2009, NVE, NPC, SPPC and their subsidiaries had approximately $5.6 billion of debt and other obligations outstanding, consisting of approximately $3.7 billion of debt at NPC, approximately $1.4 billion of debt at SPPC and approximately $485 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ senior secured debt being rated at investment grade by S&P and Moody’s, these restrictions are suspended and are no longer in effect so long as the debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.

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As of September 30, 2009, NPC and SPPC paid dividends to NVE of $69.5 million and $128.8 million, respectively. On October 19, 2009 NPC paid dividends to NVE of $7.5 million. As of September 30, 2009, NVE contributed $90.3 million to SPPC during 2009.

Credit Ratings

NVE, NPC and SPPC are currently rated by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NVE and the Utilities. The senior secured debt of NPC and SPPC is rated investment grade by these three rating organizations. As of September 30, 2009, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
NVE	Sr. Unsecured Debt	BB-	Ba3	BB
NPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	BB	Not rated	BB+
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

*Investment grade

S&P’s and Moody’s rating outlook for NVE, NPC and SPPC is Stable. Fitch’s rating outlook for NVE, NPC and SPPC is Positive.

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

NV Energy, Inc.

Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of September 30, 2009, NVE (consolidated) would be allowed to incur up to $828 million of additional indebtedness assuming an interest rate of 7%. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.

Notwithstanding these restrictions, under the terms of the debt, NPC and SPPC would still be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities. As of September 30, 2009, the combined total outstanding indebtedness and letters of credit under their respective revolving credit facilities was approximately $140 million.

If the applicable series of holding company debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade by both Moody’s and S&P (see Credit Ratings above).

Nevada Power Company

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt. As of September 30, 2009, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $750 million in long term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long term debt or the use of the Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:

Financing authority from the PUCN - As of September 30, 2009, NPC has financing authority from the PUCN to issue (1) additional long term debt up to $750 million over a two-year period ending December 31, 2010, (2) ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and (3) authority to refinance up to approximately $471 million of long-term debt securities;

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Financial covenants within NPC’s financing agreements - NPC's $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its $90 million supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of September 30, 2009, NPC was in compliance with these covenants. In order to maintain compliance with these covenants, NPC is limited to $2 billion of additional indebtedness.

All other financial covenants contained in NPC’s revolving credit facilities and its financing agreements are suspended, as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these covenants; and

c.	Financial Covenants within NVE’s financing agreements - As discussed in NVE’s Ability to Issue Debt, NPC is subject to NVE’s cap on additional consolidated indebtedness of $828 million.

Ability to Issue General and Refunding Mortgage Securities

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

NPC’s Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2009, $4 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $646 million of additional General and Refunding Mortgage Securities as of September 30, 2009. 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.

Property additions include plant-in-service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

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 NPC’s Indenture, it will reduce the amount of securities issuable under NPC’s Indenture.

Sierra Pacific Power Company

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt. As of October 28, 2009, the most restrictive of the factors below is the PUCN authority, based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:

Financing authority from the PUCN - On October 28, 2009, the PUCN approved SPPC’s request for financing authority to issue up to $350 million of long-term debt securities over a three-year period ending December 31, 2012, ongoing authority to maintain a revolving credit facility of up to $600 million, and authority to refinance up to approximately $348 million of long-term debt securities;

Financial covenants within SPPC’s financing agreements - SPPC's $332 million Amended and Restated Revolving Credit Agreement dated November 2005, contains two financial maintenance covenants. The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of September 30, 2009, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC is limited to $735 million of additional indebtedness.

All other financial covenants contained in SPPC’s revolving credit facility and financing agreements are suspended, as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations on indebtedness under these covenants; and

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c.	Financial covenants within NVE’s financing agreements - Furthermore, as discussed in NVE’s Ability to Issue Debt, SPPC is subject to NVE’s cap on additional consolidated indebtedness of $828 million.

Ability to Issue General and Refunding Mortgage Securities

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

SPPC’s Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of September 30, 2009, $1.8 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $495 million of additional General and Refunding Mortgage Securities as of September 30, 2009. 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.

Property additions include plant-in-service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

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 SPPC’s Indenture, it will reduce the amount of securities issuable under the SPPC’s Indenture.

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 NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE 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 NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

Energy Supplier Matters

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC and SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of September 30, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $67.0 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as required by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

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Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade, the maximum collateral requirement would be $11.5 million.

Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of September 30, 2009, the maximum amount of collateral the Utilities would be required to post under these agreements is approximately $82.3 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $64.1 million would be required if the Utilities are downgraded one level and an additional amount of approximately $18.2 million would be required if the Utilities are downgraded two levels.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $163.6 million during the three months ended September 30, 2009 compared to net income of $124.3 million for the same period in 2008. During the nine months ended September 30, 2009, NPC recognized net income of approximately $140.9 million compared to net income of approximately $165.5 million for the same period in 2008.

During the nine months ended September 30, 2009, NPC paid $69.5 million in dividends to NVE. On October 19, 2009, NPC paid $7.5 million in dividends to NVE.

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.

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

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

	Three Months Ended September 30,								Nine Months Ended September 30,
						Change from								Change from
	2009		2008			Prior Year %			2009		2008			Prior Year %
Operating Revenues:
Electric	$	933,520	$	826,825			12.9	%	$	1,945,818	$	1,866,220			4.3	%


Energy Costs:
Fuel for power generation		160,960		240,027			-32.9	%		455,355		613,968			-25.8	%
Purchased power		288,248		319,324			-9.7	%		541,746		577,161			-6.1	%
Deferral of energy costs-net		46,911		(80,191	)		-158	%		144,910		(44,107	)		-428.5	%
	$	496,119	$	479,160			3.5	%	$	1,142,011	$	1,147,022			-0.4	%


Gross Margin	$	437,401	$	347,665			25.8	%	$	803,807	$	719,198			11.8	%

Gross margin increased for the three months ended September 30, 2009 compared to the same period in 2008 primarily due to an increase in BTGR revenue as a result of NPC’s 2008 GRC, effective July 1, 2009. Partially offsetting this increase was a change in customer usage patterns and the termination of various transmission service agreements.

Gross margin increased for the nine months ended September 30, 2009 compared to the same period in 2008 primarily due to an increase in BTGR revenue as a result of NPC’s 2008 GRC, effective July 1, 2009, increased revenues associated with renewable energy programs, and a slight increase in average customer growth. Partially offsetting the increase was a change in customer usage patterns and the termination of various transmission service agreements.

Electric Operating Revenue

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %
Electric Operating Revenues:
Residential	$	484,561	$	435,986		11.1	%	$	939,488	$	887,173		5.9	%
Commercial		148,504		134,391		10.5	%		365,595		362,850		0.8	%
Industrial		278,728		228,141		22.2	%		578,661		537,930		7.6	%
Retail revenues		911,793		798,518		14.2	%		1,883,744		1,787,953		5.4	%
Other		21,727		28,307		-23.2	%		62,074		78,267		-20.7	%
Total Revenues	$	933,520	$	826,825		12.9	%	$	1,945,818	$	1,866,220		4.3	%

Retail sales in thousands of MWhs		7,197		7,413		-2.9	%		16,626		16,952		-1.9	%

Average retail revenue per MWh	$	126.69	$	107.72		17.6	%	$	113.30	$	105.47		7.4	%

NPC’s retail revenues increased for the three and nine months ended September 30, 2009 as compared to the same period in 2008. Retail revenues increased primarily due to increases in rates as a result of NPC’s General Rate Case (GRC), effective July 1, 2009, partially offset by decreased rates as a result of NPC’s various BTER quarterly cases and deferred energy cases (See Note 3, Regulatory Actions of the Notes to the Financial Statements). The overall rate increase was partially offset by changes in customer usage patterns and, in the case of the nine months ended September 30, 2009, milder weather during the first six months of 2009. For the three months ended September 30, 2009, the average number of residential customers decreased slightly by 0.3%; however, commercial and industrial customers increased slightly by 0.3% and 0.2%, respectively, compared to the same period in the prior year. For the nine months ended September 30, 2009, the average number of residential, commercial and industrial customers increased by 0.1%, 0.6% and 2.0%, respectively, compared to the same period in the prior year.

Electric Operating Revenues – Other decreased for the three and nine months ended September 30, 2009 compared to the same period in 2008. The decrease is primarily due to the termination of several transmission agreements, including a transmission agreement related to the Higgins Generating Station which was purchased by NPC in October 2008.

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Energy Costs

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

•		Weather
•		Generation efficiency
•		Plant outages
•		Total system demand
•		Resource constraints
•		Transmission constraints
•		Natural gas constraints
•		Long-term contracts; and
•		Mandated power purchases

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Energy Costs	$	449,208	$	559,351		-19.7	%	$	997,101	$	1,191,129		-16.3	%
Total System Demand		7,552		7,723		-2.2	%		18,033		17,872		0.9	%
Average cost per MWh	$	59.48	$	72.43		-17.9	%	$	55.29	$	66.65		-17.0	%

Energy costs, total system demand and the average cost per MWh decreased for the three months ended September 30, 2009 compared to the same period in 2008. Energy costs and the average cost per MWh decreased primarily due to a decline in natural gas prices and an increase in self generation which was more economical than purchased power, partially offset by an increase in the settlement costs for hedging instruments. For the three months ended September 30, 2009 NPC self generated approximately 66% of total system demand compared to approximately 56% for the same period in 2008. The decrease in demand for the three month period was primarily due to a decrease in customer usage as a result of change in customer usage patterns.

Energy costs and the average cost per MWh decreased for the nine months ended September 30, 2009 compared to the same period in 2008. Energy costs and the average cost per MWh decreased primarily due to a decline in natural gas prices and an increase in self generation which was more economical than purchased power, partially offset by an increase in the settlement costs for hedging instruments. For the nine months ended September 30, 2009 NPC self generated approximately 70% of total system demand compared to approximately 64% for the same period in 2008. The slight increase in total system demand was primarily due to hotter weather during May 2009.

Fuel For Power Generation

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Fuel for power generation	$	160,960	$	240,027		-32.9	%	$	455,355	$	613,968		-25.8	%

Thousands of MWhs generated		4,999		4,317		15.8	%		12,688		11,437		10.9	%

Average fuel cost per MWh of generated power	$	32.20	$	55.60		-42.1	%	$	35.89	$	53.68		-33.1	%

Fuel for power generation and the average cost per MWh decreased significantly for the three and nine months ended September 30, 2009 as compared to the same time period in 2008. These decreases were primarily due to significantly lower natural gas prices which were partially offset by an increase in cost for the settlements of hedging instruments. Volume increased primarily due to the addition of the Higgins Generating Station and the Clark Peaking Units.

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Purchased Power

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Purchased Power	$	288,248	$	319,324		-9.7	%	$	541,746	$	577,161		-6.1	%

Purchased power in thousands of MWhs		2,553		3,406		-25.0	%		5,345		6,435		-16.9	%

Average cost per MWh of purchased power	$	112.91	$	93.75		20.4	%	$	101.36	$	89.69		13.0	%

Purchased power costs decreased for the three and nine months ended September 30, 2009 compared to the same period in 2008 primarily due to a decrease in volume and lower natural gas prices partially offset by an increase in the settlement costs for hedging instruments related to tolling contracts. Volume decreased primarily as a result of an increase in self generation. The average cost per MWh increased primarily due to an increase in settlement costs for hedging instruments, partially offset by a decrease in lower natural gas prices.

Deferral of Energy Costs - Net

	Three Months								Nine Months
	Ended September 30,								Ended September 30,
	2009		2008			Change from Prior Year %			2009		2008			Change from Prior Year %

Deferred energy costs - net	$	46,911	$	(80,191	)		-158.5	%	$	144,910	$	(44,107	)		-428.5	%

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

Amounts for the three months ended September 30, 2009 and 2008 include amortization of deferred energy costs of $14.7 million and $35.7 million, respectively; and an over-collection of amounts recoverable in rates of $32.2 million in 2009 and an under-collection of $115.9 million in 2008. Amounts for the nine months ended September 30, 2009 and 2008 include amortization of deferred energy costs of $33.5 million and $123.9 million, respectively; and an over-collection of amounts recoverable in rates of $111.4 million in 2009 and an under-collection of $168 million in 2008. Amortization for both the three and nine month periods include amounts for the Western Energy Crisis Rate Case and the reinstatement of deferred energy as discussed in Note 3, Regulatory Actions, of Notes to Financial Statements in NPC’s 2008 Form 10-K.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2009		2008		Change from Prior Year %			2009		2008		Change from Prior Year %

Allowance for other funds used during construction	$	3,385	$	6,543		-48.3	%	$	16,558	$	21,093		-21.5	%

Allowance for borrowed funds used during construction	$	2,815	$	5,128		-45.1	%	$	13,483	$	16,503		-18.3	%
	$	6,200	$	11,671		-46.9	%	$	30,041	$	37,596		-20.1	%

AFUDC decreased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, due to the completion of construction of the Clark Peaking Units in late 2008, partially offset by the construction of the 500 MW natural gas generating units at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011.

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Other (Income) and Expenses

	Three Months Ended September 30,									Nine Months Ended September 30,
	2009			2008			Change from Prior Year %			2009			2008			Change from Prior Year %

Other operating expense	$	68,521		$	69,432			-1.3	%	$	206,771		$	189,144			9.3	%
Maintenance expense	$	12,014		$	12,469			-3.6	%	$	58,280		$	42,727			36.4	%
Depreciation and amortization	$	54,996		$	37,902			45.1	%	$	160,869		$	120,855			33.1	%
Interest charges on long-term debt	$	56,672		$	46,662			21.5	%	$	166,492		$	129,283			28.8	%
Interest charges-other	$	4,498		$	6,737			-33.2	%	$	17,526		$	17,952			-2.4	%
Interest accrued on deferred energy	$	(248	)	$	(2,803	)		-91.2	%	$	(2,891	)	$	(5,681	)		-49.1	%
Other income	$	(3,776	)	$	(4,116	)		-8.3	%	$	(18,726	)	$	(12,970	)		44.4	%
Other expense	$	1,537		$	2,028			-24.2	%	$	12,335		$	5,045			144.5	%

Other operating expense decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to a decrease in legal and other external services costs, and bad debt expense due to a lower reserve rate. These decreases were partially offset by an increase to pension expense, costs associated with renewable energy programs, operating leases and operating expenses for the Higgins Generating Station acquired in October 2008.

Other operating expense increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to an increase in pension expense, costs associated with renewable energy programs, operating leases and operating expenses for the Higgins Generating Station acquired in October 2008, partially offset by lower outside legal and other external services costs.

Maintenance expense decreased slightly for the three months ended September 30, 2009, compared to the same period in 2008, due to decreased costs for the Clark and Lenzie Generating Stations due to planned outages in 2008, partially offset by increased costs for the Higgins Generating Station acquired in October 2008.

Maintenance expense increased for the nine months ended September 30, 2009, compared to the same period in 2008, due to the addition of the Higgins Generating Station and increased scheduled maintenance for the Clark, Lenzie, Navajo, Reid Gardner and Silverhawk Generating Stations in 2009.

Depreciation and amortization expenses increased during the three months and nine months ended September 30, 2009, compared to the same period in 2008, as a result of increases in plant-in-service, primarily due to the completion of the Clark Peaking Units and the addition of the Higgins Generating Station in the latter part of 2008.

Interest charges on Long-Term Debt increased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the issuance of additional debt used to fund significant capital expenditures. This increase was partially offset by lower interest on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2008 Form 10-K and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q for additional information regarding long-term debt.

Interest charges-other decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to a change in estimated interest expense on uncertain tax positions recorded in the first quarter of 2009 which were subsequently reversed in the third quarter. Also contributing to the decrease in 2009 was interest expense associated with refunds for construction advances recorded in 2008. These decreases were partially offset by higher amortization costs related to new debt issues and redemptions. Interest charges-other for the nine months ended September 30, 2009, compared to the same period in 2008, decreased due to interest expense associated with refunds for construction advances recorded in 2008, offset by higher amortization costs related to new debt issues and redemptions.

Interest income accrued on deferred energy balances decreased for the three months and nine months ended September 30, 2009, as compared to the same period in 2008, due to lower carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007, and overall lower deferred energy balances. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to lower carrying charges on energy conservation programs and lower interest income on investments. These decreases were partially offset by interest income received on income tax refunds. Other income increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the settlement of outstanding legal matters associated with the Natural Gas Provider case, as discussed further in Note 7, Commitments and Contingencies of the Condensed Notes to Financial Statements, interest received on tax refunds, and higher carrying charges on energy conservation programs. These were partially offset by expiration of the amortization of gains associated with the disposition of property, lower interest income on investments and income earned in 2008 as a result of the settlement with Calpine, and the subsequent gain on sale of the stock received, as discussed further in Note 13, Commitments and Contingencies, in the Notes to Financial Statements in the 2008 Form 10-K.

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Other expense decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to lower advertising expenses in 2009. Other expense increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to adjustments resulting from the decision in NPC’s GRC. The increase in other expense for the nine months ended September 30, 2009, was also partially offset by lower advertising expenses in 2009.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the nine months ended September 30, 2009, compared to the same period in 2008, due to reduction in cash from financing activities and a slight increase in cash used for investing activities, partially offset by an increase in cash from operating activities.

Cash From Operating Activities. The increase in cash from operating activities was due primarily to the over collection of revenues in excess of fuel and purchased power costs, decreased purchased power and fuel costs, increased BTGR revenues beginning July 1, 2009, and the settlement of outstanding litigation. These increases were partially offset by increased operating and maintenance costs for new generating facilities, some of which were not included in rates until July 1, 2009, pension funding, increased interest costs, the receipt of prepaid transmission revenue in 2008 and the repayment of transmission deposits in 2009.

Cash Used By Investing Activities. Cash used for investing activities did not change significantly between the periods.

Cash From Financing Activities. Cash from financing activities decreased primarily due to a decrease in investment by NVE and increased payments on the revolving credit facility. This decrease was partially offset by the issuance of $625 million in Series U and Series V Notes.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

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

Available Liquidity as of September 30, 2009 (in millions)

Cash and Cash Equivalents	$	30.8
Balance available on Revolving Credit Facility(1)	$	555.3
	$	586.1

1 As of October 28, 2009, NPC had approximately $653.3 million available under its revolving credit facilities, which reflects amounts outstanding under letters of credit.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. NPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the NPC’s revolving credit facilities, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

NPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facilities. NPC’s long-term credit facility expires on November 4, 2010, and NPC’s $90 million Supplemental Revolving Credit Facility expires on January 3, 2010. As of October 28, 2009, NPC has borrowed approximately $10 million on its revolving credit facility.

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There have been no changes to the credit ratings of NPC in the first three quarters of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the nine months ended September 30, 2009, there were no material changes to contractual obligations as set forth in NPC’s 2008 Form 10-K, except as discussed under financing transactions below.

Financing Transactions

Tender Offer

On October 7, 2009, NPC settled its cash tender offer, which commenced on September 8, 2009 and expired on October 5, 2009 for the following securities:

•		Clark County, Nevada Industrial Development Refunding Revenue Bonds (Nevada Power Company Project) Series 2000A, in an aggregate principal amount of $100 million;
•		Coconino County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2006A, in an aggregate principal amount of $40 million; and
•		Clark County, Nevada Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2006, in an aggregate principal amount of $39.5 million (collectively, “the NPC Bonds”).

Those holders who tendered their NPC Bonds by the expiration date were entitled to receive a purchase price of $900 per $1,000 NPC Bond, plus any accrued and unpaid interest to, but not including, the date that is two business days following the October 5, 2009 expiration date. Approximately $5.7 million of the $179.5 million NPC Bonds outstanding were validly tendered and accepted by NPC. NPC financed the tendered bonds with available cash. The tendered NPC Bonds remain outstanding and have not been retired or cancelled. However, as NPC is the sole holder of the NPC Bonds, for financial reporting purposes the investment in the tendered NPC Bonds to the indebtedness will be offset for presentation purposes.

Maturity of Clark County Nevada Pollution Control Revenue Bonds, Series 2000B

On October 1, 2009 the Clark County Nevada Pollution Control Revenue Bonds, Series 2000B, in the aggregate principal amount of $15 million, matured. In July 2008, these securities were converted from auction rate securities to variable rate demand notes, as further disclosed in Note 6, Long-Term Debt in the 2008 Form 10-K. NPC purchased 100% of the bonds at that time, and remained the sole holder of these bonds until the maturity date. NPC financed the maturity with available cash.

Revolving Credit Facilities

General and Refunding Mortgage Notes, Series V

General and Refunding Mortgage Notes, Series U

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Factors Affecting Liquidity

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt. As of September 30, 2009, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $750 million in long-term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:

c.	Financial Covenants within NVE’s financing agreements - As discussed in NVE’s Ability to Issue Debt, NPC is subject to NVE’s cap on additional consolidated indebtedness of $828 million.

Ability to Issue General and Refunding Mortgage Securities

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

NPC’s Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2009, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $646 million of additional General and Refunding Mortgage Securities as of September 30, 2009. 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.

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Credit Ratings

NPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NPC. As of September 30, 2009, the ratings are as follows:

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

* Investment grade

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S&P’s and Moody’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of their respective 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.

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of September 30, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $67.0 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty, if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade, the maximum collateral requirement would be $11.5 million.

Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that NPC maintain its Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that NPC’s Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require NPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to NPC, subject to certain caps. As of September 30, 2009, the maximum amount of collateral NPC would be required to post under these agreements is approximately $45.0 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $36.8 million would be required if NPC is downgraded one level, and an additional amount of approximately $8.2 million would be required if NPC is downgraded two levels.

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SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $24.3 million for the three months ended September 30, 2009 compared to net income of $32.9 million for the same period in 2008. During the nine months ended September 30, 2009, SPPC recognized net income of approximately $58.2 million compared to $68.1 million for the same period in 2008.

During the nine months ended September 30, 2009, SPPC paid $128.8 million in dividends to NVE.

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 energy costs, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 2, Segment Information in the Condensed Notes to Financial Statements. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended September 30,								Nine Months Ended September 30,
						Change from								Change from
	2009		2008			Prior Year %			2009		2008			Prior Year %
Operating Revenues:
Electric	$	265,734	$	271,919			-2.3	%	$	734,386	$	758,612			-3.2	%
Gas		19,745		19,379			1.9	%		132,686		137,125			-3.2	%
	$	285,479	$	291,298			-2.0	%	$	867,072	$	895,737			-3.2	%

Energy Costs:
Fuel for power generation	$	89,125	$	92,845			-4.0	%	$	229,119	$	211,137			8.5	%
Purchased power		25,580		64,005			-60.0	%		92,439		251,474			-63.2	%
Deferral of energy costs-electric-net		26,646		(9,384	)		-384.0	%		68,222		(12,572	)		-642.7	%
Gas purchased for resale		11,269		13,760			-18.1	%		101,457		108,288			-6.3	%
Deferral of energy costs-gas-net		2,286		(725	)		-415.3	%		1,923		(2,296	)		-183.8	%
	$	154,906	$	160,501			-3.5	%	$	493,160	$	556,031			-11.3	%

Energy Costs by Segment:
Electric	$	141,351	$	147,466			-4.1	%	$	389,780	$	450,039			-13.4	%
Gas		13,555		13,035			4.0	%		103,380		105,992			-2.5	%
	$	154,906	$	160,501			-3.5	%	$	493,160	$	556,031			-11.3	%

Gross Margin by Segment:
Electric	$	124,383	$	124,453			-0.1	%	$	344,606	$	308,573			11.7	%
Gas		6,190		6,344			-2.4	%		29,306		31,133			-5.9	%
	$	130,573	$	130,797			-0.2	%	$	373,912	$	339,706			10.1	%

Gross margin – electric and gas, decreased slightly for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to an increase in rates offset by a decrease in customer usage as a result of milder weather.

Gross margin - - electric increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the increase in BTGR revenue as a result of SPPC’s 2007 GRC, effective July 1, 2008, increased revenues associated with renewable energy programs, and a slight increase in average customer growth. Partially offsetting the increase was a decrease in customer usage as a result of milder weather, a decrease in short-term transmission revenue and the switching of certain mining customers to DOS.

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Gross margin – gas decreased for the nine months ended September 30, 2009 compared to the same period in 2008 primarily due to decreased customer usage as a result of milder weather.

Electric Operating Revenue

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %
Electric operating revenues:
Residential	$	93,594	$	96,558		-3.1	%	$	263,287	$	256,726		2.6	%
Commercial		108,167		108,596		-0.4	%		296,671		289,327		2.5	%
Industrial		56,328		59,163		-4.8	%		151,671		187,942		-19.3	%
Retail revenues		258,089		264,317		-2.4	%		711,629		733,995		-3.0	%
Other		7,645		7,602		0.6	%		22,757		24,617		-7.6	%
Total revenues	$	265,734	$	271,919		-2.3	%	$	734,386	$	758,612		-3.2	%

Retail sales in thousands of MWhs		2,206		2,339		-5.7	%		6,128		6,537		-6.3	%

Average retail revenue per MWh	$	116.99	$	113.00		3.5	%	$	116.13	$	112.28		3.4	%

SPPC’S retail revenues decreased for the three and nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to lower industrial revenue and decreased customer usage due to cooler summer weather and in the case of the nine month period, milder spring weather and warmer winter weather. Industrial revenues decreased primarily due to the transition of Cortez Mine to DOS effective November 1, 2008, and a retail service agreement with Newmont Mining Corporation (“Newmont”) beginning June 1, 2008. These decreases were partially offset by increased retail rates. Retail rates increased as a result of SPPC’s GRC effective July 1, 2008.

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

For the three months ended September 30, 2009, the average number of residential and industrial customers decreased 0.1% and 3.0%, respectively, while the commercial customers increased 1.9%. For the nine months ended September 30, 2009, the average number of residential customers decreased 0.1% and the average number of commercial and industrial customers increased 1.6% and 1.9%, respectively.

Electric Operating Revenues – Other increased for the three months ended September 30, 2009, compared to the same period in 2008 primarily due to the amortization of Cortez Mine impact fees related to the departure of Cortez from SPPC’s system. Electric Operating Revenues – Other decreased for the nine month period primarily due to decreased transmission revenues which were partially offset by the amortization of the Cortez fees.

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Gas Operating Revenues

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %
Gas operating revenues:
Residential	$	10,740	$	10,269		4.6	%	$	74,410	$	79,074		-5.9	%
Commercial		4,913		4,885		0.6	%		35,191		37,768		-6.8	%
Industrial		2,155		1,873		15.1	%		11,779		13,726		-14.2	%
Retail revenues		17,808		17,027		4.6	%		121,380		130,568		-7.0	%
Wholesale revenue		1,406		1,858		-24.3	%		9,567		4,663		105.2	%
Miscellaneous		531		494		7.5	%		1,739		1,894		-8.2	%
Total revenues	$	19,745	$	19,379		1.9	%	$	132,686	$	137,125		-3.2	%

Retail sales in thousands of Dths		1,183		1,231		-3.9	%		9,549		10,420		-8.4	%

Average retail revenue per Dth	$	15.05	$	13.83		8.8	%	$	12.71	$	12.53		1.4	%

SPPC’s retail gas revenues increased for the three months ended September 30, 2009 as compared to the same period in the prior year primarily due to increased retail rates. Retail rates increased as a result of SPPC’s various Natural Gas and Propane BTER quarterly updates. The average number of retail customers for the three months ended September 30, 2009 increased 0.3%.

SPPC’S retail gas revenues decreased for the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to decreased customer usage as a result of warmer winter weather and lower rates prior to April 1, 2009. The average number of retail customers for the nine months ended September 30, 2009 increased 0.3%.

Wholesale revenues decreased for the three month period ended September 30, 2009, compared to the same period in 2008 primarily due to decreased availability of gas for wholesale sales. Wholesale revenues increased for the nine months ended September 30, 2009, compared to prior year due to increased availability of gas for wholesale sales during the first and second quarter of 2009.

Energy Costs

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

•		Weather
•		Plant outages
•		Total system demand
•		Resource constraints
•		Transmission constraints
•		Gas transportation constraints
•		Natural gas constraints
•		Long-term contracts
•		Mandated power purchases; and
•		Generation efficiency

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Energy Costs	$	114,705	$	156,850		-26.9	%	$	321,558	$	462,611		-30.5	%
Total System Demand		2,352		2,455		-4.2	%		6,590		6,986		-5.7	%
Average cost per MWh	$	48.77	$	63.89		-23.7	%	$	48.79	$	66.22		-26.3	%

Energy costs and the average cost per MWh for the three and nine months ended September 30, 2009 decreased compared to the same period in 2008 due to the significant decrease in natural gas prices and lower purchase power costs during the first six months of 2009 as a result of the Newmont Mining Corporation power purchase agreement discussed above in Electric Operating Revenues. Total system demand decreased due to milder weather, certain customers switching to DOS and a change in customer usage patterns. For the three months ended September 30, 2009, self generation represented 72% of total system compared to 61% for the same period in 2008. For the nine months ended September 30, 2009, self generation represented 64% of total system compared to 47% for the same period in 2008.

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Fuel for Power Generation

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Fuel for power generation	$	89,125	$	92,845		-4.0	%	$	229,119	$	211,137		8.5	%

Thousands of MWh generated		1,696		1,478		14.7	%		4,219		3,325		26.9	%

Average fuel cost per MWh of generated power	$	52.55	$	62.82		-16.3	%	$	54.31	$	63.50		-14.4	%

Fuel for power generation and average cost per MWh decreased for the three months ended September 30, 2009 as compared to the same period in 2008 due primarily to lower natural gas prices partially offset by an increase in the settlement costs for hedging instruments. The volume increased due to greater reliance on internal generation.

Fuel for power generation and volume increased for the nine months ended September 30, 2009 as compared to the same period in 2008 due to a greater reliance on the Tracy Generation Station. The average cost per MWh decreased for the nine months primarily due to lower natural gas prices partially offset by an increase in the settlement costs for hedging instruments.

Purchased Power

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Purchased power	$	25,580	$	64,005		-60.0	%	$	92,439	$	251,474		-63.2	%

Purchased power in thousands of MWhs		656		977		-32.9	%		2,371		3,661		-35.2	%

Average cost per MWh of purchased power	$	38.99	$	65.51		-40.5	%	$	38.99	$	68.69		-43.2	%

Purchased power costs and the average cost per MWh decreased for the three months ended September 30, 2009 as compared to the same period in 2008 primarily due to a decrease in natural gas prices. The volume of MWhs decreased for the three months ended September 30, 2009 as compared to the same period in 2008 primarily due to increased reliance on internal generation.

Purchased power costs and the average cost per MWh decreased for the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to a decrease in natural gas prices and a power purchase agreement with Newmont Mining Corporation, as discussed above in Electric Operating Revenues, whereby SPPC purchases power substantially below current market prices. However, SPPC is limited by the volume it can purchase under these lower rates. The volume of MWhs decreased for the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to increased reliance on internal generation.

Gas Purchased for Resale

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %


Gas purchased for resale	$	11,269	$	13,760		-18.1	%	$	101,457	$	108,288		-6.3	%

Gas purchased for resale (in thousands of Dths)		1,670		1,510		10.6	%		12,141		11,221		8.2	%

Average cost per Dth	$	6.75	$	9.11		-25.9	%	$	8.36	$	9.65		-13.4	%

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Gas purchased for resale and average cost per decatherm decreased for the three months and nine months ended September 30, 2009 as compared to the same period in 2008. The decrease is primarily due to a decrease in natural gas prices. Volume increased for the three and nine months ended September 30, 2009 compared to the same period in 2008 primarily due to excess availability of gas, due to milder weather. The excess is sold to wholesale customers.

Deferral of Energy Costs – Electric - Net

	Three Months Ended September 30,								Nine Months Ended September 30,
	2009		2008			Change from Prior Year %			2009		2008			Change from Prior Year %

Deferred energy costs - electric – net	$	26,646	$	( 9,384	)		-384.0	%	$	68,222	$	(12,572	)		-642.7	%
Deferred energy costs - gas – net	$	2,286	$	(725	)		- 415.3	%	$	1,923	$	(2,296	)		-183.8	%
	$	28,932	$	(10,109	)				$	70,145	$	(14,868	)

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

Deferral of energy costs - electric – net for the three months ended September 30, 2009 and 2008 reflect amortization of deferred energy costs of $(0.4) million and $(2.0) million respectively; and an over-collection of amounts recoverable in rates of $27.0 million in 2009, and an under-collection of $7.4 million in 2008. For the nine months ended September 30, 2009 and 2008, amortization of deferred energy costs were ($1.6) million and $16.6 million, respectively; with an over-collection of amounts recoverable in rates of $69.8 million in 2009, and under-collection of $29.2 million in 2008.

Deferred energy costs - gas - net for the three months ended September 30, 2009 and 2008 reflect amortization of deferred energy costs of $0.0 million, and ($0.1) million, respectively; and an over-collection of amounts recoverable in rates in 2009 of $2.3 million and an under-collection of $0.6 million in 2008. For the nine months ended September 30, 2009 and 2008, amortization of deferred energy costs were $0.0 million and ($1.0) million, respectively; with an over-collection of amounts recoverable in rates of $1.9 million and under-collection of $1.3 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2009		2008		Change from Prior Year %			2009		2008		Change from Prior Year %

Allowance for other funds used during construction	$	942	$	1,322		-28.8	%	$	2,535	$	11,842		-78.6	%

Allowance for borrowed funds used during construction	$	864	$	1,050		-17.7	%	$	2,364	$	8,915		-73.5	%
	$	1,806	$	2,372		-23.9	%	$	4,899	$	20,757		-76.4	%

AFUDC decreased for the three and nine months ended September 30, 2009 compared to the same period in 2008, primarily due to the completion of the Tracy Generating Station in July of 2008, which resulted in a decrease to the Construction Work-In-Progress (CWIP) balance.

Other (Income) and Expense

	Three Months Ended September 30,									Nine Months Ended September 30,
	2009			2008			Change from Prior Year %			2009			2008			Change from Prior Year %

Other operating expense	$	38,843		$	35,474			9.5	%	$	123,748		$	103,744			19.3	%
Maintenance expense	$	8,173		$	7,868			3.9	%	$	23,939		$	22,204			7.8	%
Depreciation and amortization	$	27,545		$	21,343			29.1	%	$	80,043		$	64,801			23.5	%
Interest charges on long-term debt	$	16,760		$	18,635			-10.1	%	$	49,820		$	55,975			-11.0	%
Interest charges-other	$	891		$	1,407			-36.7	%	$	4,017		$	4,398			-8.7	%
Interest accrued on deferred energy	$	2,047		$	454			350.9	%	$	3,764		$	1,639			129.7	%
Other income	$	(3,792	)	$	(2,367	)		60.2	%	$	(12,299	)	$	(11,331	)		8.5	%
Other expense	$	813		$	749			8.5	%	$	4,601		$	5,430			-15.3	%

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Other operating expense increased for the three and nine months ended September 30, 2009, compared to the same period in 2008, primarily due to higher pension expense, costs related to renewable energy programs and operating expenses for the Tracy Generating Station expansion placed in service in summer 2008. Additionally, contributing to higher expenses was lower provisions for bad debt in 2008 compared to 2009.

Maintenance expense increased for the three and nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the addition of the Tracy Generating Station expansion that became operational in summer of 2008, partially offset by outages at Valmy Generating Station for boiler repairs in 2008 and lower maintenance cost for Ft. Churchill in 2009.

Depreciation and amortization expenses increased for the three and nine months ended September 30, 2009 compared to the same period in 2008, as a result of increases in plant-in-service, primarily due to the completion of the Tracy Generating Station in July of 2008.

Interest charges on long-term debt decreased for the three months and nine months ended September 30, 2009 compared to the same periods in 2008 primarily due to interest savings related to repurchased debt, lower interest rates on variable rate debt, and the redemption of $99 million Series A General and Refunding Mortgage Bonds in June 2008. These amounts were partially offset by the issuance of $250 million Series Q General and Refunding Mortgage Notes in September 2008, and the addition of $150 million to its 6.0% Series M General and Refunding Mortgage Notes in August 2009. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2008 10-K and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q for additional information regarding long-term debt .

Interest charges-other decreased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, due to several items, none of which are material.

Interest expense accrued on deferred energy balances increased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, due to higher deferred energy balances in 2009. See Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income increased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to interest received for income tax refunds, offset by lower miscellaneous carrying charges. Other income increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to gains on the disposition of property in 2009 and interest received for tax refunds, offset by income earned in 2008 related to the reinstatement of previously disallowed costs associated with Pinon Pine and the settlement with Calpine as discussed in Note 3, Regulatory Actions and Note 13, Commitments and Contingencies of the Notes to Financial Statements in the 2008 Form 10-K.

Other expense increased for the three months ended September 30, 2009, compared to the same period in 2008, due to several items, none of which are material. Other expense decreased during the nine months ended September 30, 2009, when compared to the same period in 2008, due to lower advertising costs in 2009 and adjustments resulting from the decision in SPPC’s GRC in 2008. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2008 10-K for further information.

ANALYSIS OF CASH FLOWS

Cash flows increased during the nine months ended September 30, 2009 compared to the same period in 2008 due to an increase in cash from operating activities and a decrease in cash used by investing activities, partially offset by a decrease in cash from financing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to the over collection of revenues in excess of fuel and purchased power costs, an increase in BTGR revenues as a result of SPPC’s 2007, GRC, partially offset by funding of pension plans and higher balances for fuel and purchased power costs at year end December 31, 2008, that were subsequently paid in 2009.

Cash Used By Investing Activities. Cash used by investing activities did not change significantly between the periods.

Cash From Financing Activities. The decrease in cash from financing activities is primarily due to increased dividends paid to the holding company, NVE and the reacquisition of $40 million Series 2007A variable rate notes due 2036, partially offset by the issuance of $150 million Series M notes and the investment by parent.

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LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

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

Available Liquidity as of September 30, 2009 (in millions)
Cash and Cash Equivalents	$	58.4
Balance available on Revolving Credit Facility(1)	$	316.1
	$	374.5

1 As of October 28, 2009, SPPC had approximately $316.9 million available under its revolving credit facility, which reflects amounts outstanding under letters of credit.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs. SPPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the SPPC’s revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

SPPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facility. SPPC’s long-term credit facility expires on November 4, 2010. As of October 28, 2009, SPPC does not have any borrowings outstanding on its revolving credit facility.

There have been no changes to the credit ratings of SPPC in the first three quarters of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to SPPC may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the nine months ended September 30, 2009, there were no material changes to contractual obligations as set forth in SPPC’s 2008 Form 10-K, except as discussed under financing transactions below.

Financing Transactions

Tender Offer

On October 7, 2009, SPPC settled its cash tender offer, which commenced on September 8, 2009 and expired on October 5, 2009 for the following securities:

•		Washoe County, Nevada Gas Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A, in an aggregate principal amount of $58.7 million;
•		Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B, in an aggregate principal amount of $75 million; and
•		Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C, in an aggregate principal amount of $84.8 million (collectively, “the SPPC Bonds”).

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General and Refunding Mortgage Notes, Series M

Revolving Credit Facility

On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, due November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $332 million.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In January 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds, until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.

Factors Affecting Liquidity

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt. As of October 28, 2009, the most restrictive of the factors below is the PUCN authority, based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:

c.	Financial covenants within NVE’s financing agreements - Furthermore, as discussed in NVE’s Ability to Issue Debt, SPPC is subject to NVE’s cap on additional consolidated indebtedness of $828 million.

Ability to Issue General and Refunding Mortgage Securities

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

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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.

Property Additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Credit Ratings

SPPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering SPPC. As of September 30, 2009, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

* Investment grade

S&P’s, and Moody’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.

Cross Default Provisions

None of the financing agreements of SPPC contains a cross-default provision that would result in an event of default by SPPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, 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.

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. Under the net mark-to-market value as of September 30, 2009 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.

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Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that SPPC maintain its Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that SPPC’s Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require SPPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to SPPC, subject to certain caps. As of September 30, 2009, the maximum amount of collateral SPPC would be required to post under these agreements is approximately $37.3 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $27.3 million would be required if SPPC is downgraded one level and an additional amount of approximately $10.0 million would be required if SPPC is downgraded two levels.

REGULATORY PROCEEDINGS (UTILITIES)

NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and the CPUC. In addition, the PUCN, the CPUC or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE 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 NVE, NPC and/or SPPC and/or any other affiliated company.

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit 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 ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover or refund any under or over collection of prior energy costs and the BTER Updates recover current energy costs. As of September 30, 2009, NPC’s and SPPC’s balance sheets included approximately $137 million and over-collections of $104 million, respectively, of deferred energy costs, which $247 million and over-collections of $33 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

Rate case applications filed in 2008 and 2009, as well as other regulatory matters such as the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and in the 2008 Form 10-K.

RECENT PRONOUNCEMENTS

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

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ITEM 3A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2009, NVE, 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).

September 30, 2009

		Expected Maturity Date
									Fair
		2009	2010	2011	2012	2013	Thereafter	Total	Value
Long-term Debt
	NVE
	Fixed Rate	$ -	$ -	$ -	$ 63,670	$ -	$ 421,539	$ 485,209	$ 505,090
	Average Interest Rate	-	-	-	7.80%	-	7.77%	7.78%

	NPC
	Fixed Rate	$ -	$ -	$ 364,000	$ 130,000	$ -	$ 2,894,335	$ 3,388,335	$ 3,690,086
	Average Interest Rate	-	-	8.14%	6.50%	-	6.53%	6.70%
	Variable Rate	$ -	$ 108,000	$ -	$ -	$ -	$ 179,500	$ 287,500	$ 287,500
	Average Interest Rate	-	1.27%	-	-	-	1.08%	1.15%

	SPPC
	Fixed Rate	$ -	$ -	$ -	$ 100,000	$ 250,000	$ 775,000	$ 1,125,000	$ 1,200,460
	Average Interest Rate	-	-	-	6.25%	5.45%	6.31%	6.12%
	Variable Rate	$ -	$ -	$ -	$ -	$ -	$ 218,500	$ 218,500	$ 218,500
	Average Interest Rate	-	-	-	-	-	1.11%	1.11%

	Total Debt	$ -	$ 108,000	$ 364,000	$ 293,670	$ 250,000	$ 4,488,874	$ 5,504,544	$ 5,901,636

Commodity Price Risk

See the 2008 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, 2008.

Credit Risk

The Utilities monitor and manage credit risk with their counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with counterparties was approximately $73.7 million as of September 30, 2009, compared to amounts of $334.3 million at December 31, 2008, and $266.3 million at September 30, 2008. The decrease is primarily due to lower market prices for physical electric contracts and lower contract prices for natural gas contracts.

ITEM 4 and 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

NVE, 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, 2009, 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 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

As of the date of this report, there have been no material changes with regard to administrative and judicial proceedings involving regulatory, environmental and other matters as disclosed in NVE’s, NPC’s and SPPC’s 2008 Form 10-K, and quarterly reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, except as discussed below.

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC. The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy Supply Company, American Electric Power Service Corporation and BP Energy, and stayed the case pending settlement discussions. The Utilities, together with other interested parties, have settled and resolved all claims against BP Energy (“BP Settlement”). On August 25, 2009, the BP Settlement received final approval by the FERC to which BP Energy was ordered to settle with NPC for an immaterial amount in return for NPC and the BCP’s release of all claims against BP Energy. On September 15, 2009, the Utilities, together with other interested parties, reached an agreement in principle with American Electric Power Service Corporation (“AEP Settlement”). The Utilities previously had negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron. The Utilities continue discussions with Allegheny Energy Supply Company. Management cannot predict the timing or outcome of a decision in this matter.

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 7, Commitments and Contingencies, in the Condensed Notes to Financial Statements for further discussion of other legal matters.

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE 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 2008 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 NVE’s, NPC’s and SPPC’s 2008 Form 10-K, and quarterly reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009.

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

None.

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6.EXHIBITS

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

(12) NV Energy, Inc.:

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) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

31.1 Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

31.4 Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

(32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

32.1 Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

32.4 Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

Table of Contents

SIGNATURES

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


	NV Energy, Inc.
	(Registrant)

Date: October 29, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: October 29, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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

Date: October 29, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: October 29, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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

Date: October 29, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: October 29, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

Table of Contents

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation

1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

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

NV Energy, Inc.:	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Nevada Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
Sierra Pacific Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

Class		Outstanding at October 28, 2009
Common Stock, $1.00 par value of NV Energy, Inc.		234,684,457 Shares

PART I – FINANCIAL INFORMATION

Acronyms and Terms			3

ITEM 1.		Financial Statements

	NV Energy, Inc.

		Consolidated Balance Sheets – September 30, 2009 and December 31, 2008………………………………………………......................................................................	4
		Consolidated Income Statements – Three Months and Nine Months Ended September 30, 2009 and 2008.........................................................................................	5
		Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2009 and 2008……………...........................................................................................	6

	Nevada Power Company

		Consolidated Balance Sheets – September 30, 2009 and December 31, 2008………………………………………………......................................................................	7
		Consolidated Income Statements – Three Months and Nine Months Ended September 30, 2009 and 2008.........................................................................................	8
		Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2009 and 2008……………...........................................................................................	9

	Sierra Pacific Power Company

		Consolidated Balance Sheets – September 30, 2009 and December 31, 2008………………………………………………......................................................................	10
		Consolidated Income Statements – Three Months and Nine Months Ended September 30, 2009 and 2008.........................................................................................	11
		Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2009 and 2008……………...........................................................................................	12

		Condensed Notes to Consolidated Financial Statements…………………………………………………..................................................................................................	13

ITEM 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations……………............................................................................................	29

		NV Energy, Inc………………………………………………………………………………………………………………..............................................................................	34
		Nevada Power Company……………………………………………………………………………………………………..............................................................................	39
		Sierra Pacific Power Company……………………………………………………………………………….....................................................................................................	48

ITEM 3.		Quantitative and Qualitative Disclosures about Market Risk…………………………………………………………............................................................................	58

ITEM 4 and 4T.		Controls and Procedures…………………………………………………………………………………………………................................................................................	58

PART II – OTHER INFORMATION

ITEM 1.		Legal Proceedings…………………………………………………………………………………………………………...............................................................................	59
ITEM 1A.		Risk Factors…………………………………………………………………………………………………………………..............................................................................	59
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds…………………………………………………………….........................................................................	59
ITEM 3.		Defaults Upon Senior Securities…………………………………………………………………………………………...............................................................................	60
ITEM 4.		Submission of Matters to a Vote of Security Holders……………………………………………………………………...........................................................................	60
ITEM 5.		Other Information…………………………………………………………………………………………………………................................................................................	60
ITEM 6.		Exhibits……………………………………………………………………………………………………………………...................................................................................	61

Signature Page and Certifications…………………………………………………………………………………………………………...........................................................................................			62

	Nine Months Ended
	September 30,						Year Ended December 31,
	2009			2008			2008			2007			2006			2005			2004

EARNINGS AS DEFINED:
Income From Continuing Operations
After Interest Charges	$	178,785		$	210,975		$	208,887		$	197,295		$	279,792		$	86,137		$	30,842
Income Taxes		80,704			99,146			95,354			87,555			145,605			43,118			18,050
Income From Continuing Operations
before Income Taxes		259,489			310,121			304,241			284,850			425,397			129,255			48,892

Fixed Charges		272,448			243,549			335,868			310,876			336,024			319,654			324,969
Capitalized Interest (allowance for borrowed funds used during construction)		(15,847	)		(25,418	)		(29,527	)		(25,967	)		(17,119	)		(24,691	)		(8,587	)
Preferred Stock Dividend Requirement		-			-			-			-			(3,602	)		(6,000	)		(6,000	)

Total	$	516,090		$	528,252		$	610,582		$	569,759		$	740,700		$	418,218		$	359,274

FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)	$	272,448		$	243,549		$	335,868		$	310,876		$	332,422		$	313,654		$	318,969
Preferred Stock Dividend Requirement		-			-			-			-			3,602			6,000			6,000

Total	$	272,448		$	243,549		$	335,868		$	310,876		$	336,024		$	319,654		$	324,969

RATIO OF EARNINGS TO FIXED CHARGES		1.89			2.17			1.82			1.83			2.20			1.31			1.11