Nevada Power 10Q 2010 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 2010

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

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

1-08788	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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o (Response applicable to all registrants)

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

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

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

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

Class		Outstanding at October 28, 2010
Common Stock, $1.00 par value of NV Energy, Inc.		235,176,008 Shares

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.

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

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

NV ENERGY, INC. NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY QUARTERLY REPORTS ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2010 TABLE OF CONTENTS
	PART I – FINANCIAL INFORMATION
	Acronyms & Terms			3

	ITEM 1.	Financial Statements

		NV Energy, Inc.
			Consolidated Income Statements – Three and Nine Months Ended September 30, 2010 and 2009	5
			Consolidated Balance Sheet – September 30, 2010 and December 31, 2009	6
			Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009	8
		Nevada Power Company
			Consolidated Income Statements – Three and Nine Months Ended September 30, 2010 and 2009	9
			Consolidated Balance Sheet – September 30, 2010 and December 31, 2009	10
			Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009	12
		Sierra Pacific Power Company
			Consolidated Income Statements – Three and Nine Months Ended September 30, 2010 and 2009	13
			Consolidated Balance Sheet – September 30, 2010 and December 31, 2009	14
			Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009	16
		Condensed Notes to Financial Statements
			Note 1. Summary of Significant Accounting policies	17
			Note 2. Segment Information	18
			Note 3. Regulatory Actions	20
			Note 4. Long-Term Debt	22
			Note 5. Fair Value of Financial Instruments	23
			Note 6. Derivatives and Hedging Activities	23
			Note 7. Retirement Plan and Post-Retirement Benefits	25
			Note 8. Commitments and Contingencies	28
			Note 9. Earnings Per Share (NVE)	30
			Note 10. Assets Held for Sale	31
			Note 11. Shareholders’ Equity	32

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34

		NV Energy, Inc.		41
		Nevada Power Company		45
		Sierra Pacific Power Company		53

	ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		64

	ITEM 4 and 4T.	Controls and Procedures		64

	PART II – OTHER INFORMATION

	ITEM 1.	Legal Proceedings		65
	ITEM 1A.	Risk Factors		65
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		65
	ITEM 3.	Defaults Upon Senior Securities		65
	ITEM 5.	Other Information		66
	ITEM 6.	Exhibits		67

	Signature Page and Certifications			69

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

Acronym/Term		Meaning

2009 Form 10-K		NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K, as amended by a Form 10-K/A, for the year ended December 31, 2009
AFUDC-debt		Allowance for Borrowed Funds Used During Construction
AFUDC-equity		Allowance for Equity Funds Used During Construction
ASD		Advanced Service Delivery (now known as NV Energize)
ASU		Accounting Standards Update
BCP		Bureau of Consumer Protection
BOD		Board of Directors
BTER		Base Tariff Energy Rate
BTGR		Base Tariff General Rate
CalPeco		California Pacific Electric Company
Clark Generating Station		550 megawatt nominally rated William Clark Generating Station
CPUC		California Public Utilities Commission
CWIP		Construction Work-In-Progress
d/b/a		Doing business as
DEAA		Deferred Energy Accounting Adjustment
DOE		Department of Energy
DSM		Demand Side Management
Dth		Decatherm
EEC		Ely Energy Center
EEIR		Energy Efficiency Implementation Rate
EEPR		Energy Efficiency Program Rate
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		Generally Accepted Accounting Principles in the United States
GBT		Great Basin Transmission, LLC
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
kV		Kilovolt
Lenzie Generating Station		1,102 megawatt nominally rated Chuck Lenzie Generating Station
LIBOR		London Interbank Offered Rate
MMBtu		Million British Thermal Units
Mohave Generating Station		1,580 megawatt nominally rated Mohave Generating Station
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 Credit Agreement		$600 million Revolving Credit Facility entered into in April 2010 between NPC and Wells Fargo, N.A., as administrative agent for the lenders a party thereto
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 Trust Company N.A., as Trustee
NRSRO		Nationally Recognized Statistical Rating Organization
NVE		NV Energy, Inc.
NV Energize		Advanced Service Delivery (formerly known as ASD)
ON Line		250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC		Portfolio Energy Credit
Portfolio Standard		Renewable Energy Portfolio Standard
PPA		Purchased Power Agreement
PUCN		Public Utilities Commission of Nevada
Reid Gardner Generating Station		325 megawatt nominally rated Reid Gardner Generating Station
REPR		Renewable Energy Program Rate
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 Credit Agreement		$250 million Revolving Credit Facility entered into in April 2010 between SPPC and Bank of America, N.A., as administrative agent for the lenders a party thereto
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 Trust Company N.A., as Trustee
TMWA		Truckee Meadows Water Authority

Tracy Generating Station		541 megawatt nominally rated Frank A. Tracy Generating Station
TRED		Temporary Renewable Energy Development
TUA		Transmission Use and Capacity Exchange Agreement, by and among Nevada Power Company (d/b/a NV Energy) and Sierra Pacific Power Company (d/b/a NV Energy) and Great Basin Transmission, LLC, dated as of August 20, 2010
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
VIE		Variable Interest Entity
WSPP		Western Systems Power Pool

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

OPERATING REVENUES	$	1,131,561		$	1,219,007		$	2,633,891		$	2,812,915

OPERATING EXPENSES:
Fuel for power generation		247,233			250,085			650,514			684,474
Purchased power		249,854			313,828			522,538			634,185
Gas purchased for resale		10,823			11,269			101,536			101,457
Deferred energy		34,055			75,843			106,554			215,055
Other operating expenses		116,263			107,992			329,435			332,555
Maintenance		23,126			20,187			77,715			82,219
Depreciation and amortization		83,423			82,541			249,067			240,912
Taxes other than income		15,420			15,177			47,532			43,577
Total Operating Expenses		780,197			876,922			2,084,891			2,334,434
OPERATING INCOME		351,364			342,085			549,000			478,481

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $6,485, $3,679, $17,349 and $15,847)		(80,789	)		(84,804	)		(241,625	)		(250,996	)
Interest income (expense) on regulatory items		(3,685	)		(1,799	)		(8,753	)		(873	)
AFUDC-equity		7,824			4,327			20,915			19,093
Other income		9,246			7,749			30,524			31,209
Other expense		(4,313	)		(2,387	)		(17,038	)		(17,425	)
Total Other Income (Expense)		(71,717	)		(76,914	)		(215,977	)		(218,992	)
Income Before Income Tax Expense		279,647			265,171			333,023			259,489

Income tax expense		96,901			82,525			115,052			80,704

NET INCOME	$	182,746		$	182,646		$	217,971		$	178,785

Amount per share basic and diluted - (Note 9)
Net income per share - basic	$	0.78		$	0.78		$	0.93		$	0.76
Net income per share - diluted	$	0.77		$	0.78		$	0.92		$	0.76

Weighted Average Shares of Common Stock Outstanding - basic		235,117,058			234,629,761			234,991,208			234,479,605
Weighted Average Shares of Common Stock Outstanding - diluted		236,477,187			235,368,919			236,136,725			235,025,554
Dividends Declared Per Share of Common Stock	$	0.11		$	0.10		$	0.33		$	0.30

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

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)



		September 30,		December 31,
		2010		2009

ASSETS

Current Assets:
Cash and cash equivalents		$	380,757	$	62,706
Accounts receivable less allowance for uncollectible accounts:
	2010 - $31,816; 2009 - $32,341		471,349		400,911
Materials, supplies and fuel, at average cost			118,546		124,040
Risk management assets (Note 6)			6,993		27,558
Income taxes receivable			13,839		-
Deferred income taxes			164,309		87,562
Other current assets			43,823		44,298
Total Current Assets			1,199,616		747,075

Utility Property:
Plant in service			10,990,794		10,833,622
Construction work-in-progress			964,648		716,128
Total			11,955,442		11,549,750
Less accumulated provision for depreciation			3,044,377		2,884,199
Total Utility Property, Net			8,911,065		8,665,551

Investments and other property, net			48,526		51,169

Deferred Charges and Other Assets:
Deferred energy (Note 3)			120,675		138,963
Regulatory assets			1,231,571		1,218,778
Regulatory asset for pension plans			254,033		264,892
Risk management assets (Note 6)			64		6,732
Other deferred charges and assets			151,014		173,145
Total Deferred Charges and Other Assets			1,757,357		1,802,510

Assets Held for Sale (Note 10)			152,399		147,158

TOTAL ASSETS		$	12,068,963	$	11,413,463

(Continued)

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)



	September 30,			December 31,
	2010			2009

LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities:
Current maturities of long-term debt	$	356,538		$	134,474
Accounts payable		324,488			352,000
Accrued expenses		118,641			134,328
Risk management liabilities (Note 6)		57,113			66,871
Deferred energy (Note 3)		307,889			191,405
Other current liabilities		69,334			67,301
Total Current Liabilities		1,234,003			946,379

Long-term debt		5,313,407			5,303,357

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		1,277,707			1,072,780
Deferred investment tax credit		20,385			22,541
Accrued retirement benefits		136,267			149,925
Risk management liabilities		915			2,233
Regulatory liabilities		410,455			386,019
Other deferred credits and liabilities		278,114			280,560
Total Deferred Credits and Other Liabilities		2,123,843			1,914,058

Liabilities Held for Sale (Note 10)		29,196			25,747

Shareholders' Equity:
Common stock ($1.00 par value; 350 million shares authorized; 235,172,624 and 234,834,169 issued and outstanding for 2010 and 2009, respectively)		235,173			234,834
Other paid-in capital		2,704,077			2,700,329
Retained earnings		435,658			295,247
Accumulated other comprehensive loss		(6,394	)		(6,488	)
Total Shareholders' Equity		3,368,514			3,223,922

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	12,068,963		$	11,413,463

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

(Concluded)

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


	For the Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	217,971		$	178,785
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		249,067			240,912
Deferred taxes and deferred investment tax credit		129,459			115,389
AFUDC-equity		(20,915	)		(19,093	)
Deferred energy		134,969			221,321
Gain on sale of asset		(7,575	)		-
Amortization of other regulatory assets		59,643			69,701
Deferred rate increase		(6,250	)		(61,795	)
Other, net		8,922			3,282
Changes in certain assets and liabilities:
Accounts receivable		(82,833	)		(124,976	)
Materials, supplies and fuel		5,883			3,246
Other current assets		475			5,602
Accounts payable		35,110			(28,001	)
Accrued retirement benefits		(13,658	)		(36,881	)
Other current liabilities		(13,589	)		(26,282	)
Risk management assets and liabilities		10,086			3,175
Other deferred assets		(4,912	)		(11,248	)
Other regulatory assets		(41,679	)		(52,671	)
Other deferred liabilities		(4,850	)		(25,291	)
Net Cash from Operating Activities		655,324			455,175

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(520,175	)		(670,023	)
Proceeds from sale of asset		18,225			-
Customer advances for construction		(6,030	)		(6,009	)
Contributions in aid of construction		46,217			48,956
Investments and other property - net		(9,090	)		(19	)
Net Cash used by Investing Activities		(470,853	)		(627,095	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		660,711			1,273,649
Retirement of long-term debt		(453,656	)		(994,275	)
Sale of Common Stock		4,086			4,162
Dividends paid		(77,561	)		(70,401	)
Net Cash from Financing Activities		133,580			213,135

Net Increase in Cash and Cash Equivalents		318,051			41,215
Beginning Balance in Cash and Cash Equivalents		62,706			54,359
Ending Balance in Cash and Cash Equivalents	$	380,757		$	95,574

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	264,974		$	257,593
Income taxes	$	14		$	14
Significant non-cash transactions:
Accrued construction expenses as of September 30,	$	65,163		$	76,006
Capital lease obligations incurred	$	15,336		$	-

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

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

OPERATING REVENUES	$	872,986		$	933,520		$	1,840,745		$	1,945,818

OPERATING EXPENSES:
Fuel for power generation		181,100			160,960			469,282			455,355
Purchased power		216,309			288,248			412,276			541,746
Deferred energy		22,296			46,911			81,719			144,910
Other operating expenses		75,798			68,521			208,374			206,771
Maintenance		15,707			12,014			50,945			58,280
Depreciation and amortization		56,575			54,996			169,330			160,869
Taxes other than income		9,038			8,970			28,857			26,394
Total Operating Expenses		576,823			640,620			1,420,783			1,594,325
OPERATING INCOME		296,163			292,900			419,962			351,493

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $5,787, $2,815, $15,763 and $13,483)		(54,144	)		(58,355	)		(161,496	)		(170,535	)
Interest income (expense) on regulatory items		(1,157	)		248			(1,965	)		2,891
AFUDC-equity		6,795			3,385			18,555			16,558
Other income		3,842			3,776			9,084			18,726
Other expense		(3,034	)		(1,537	)		(9,338	)		(12,335	)
Total Other Income (Expense)		(47,698	)		(52,483	)		(145,160	)		(144,695	)
Income Before Income Tax Expense		248,465			240,417			274,802			206,798

Income tax expense		84,337			76,826			93,216			65,857

NET INCOME	$	164,128		$	163,591		$	181,586		$	140,941


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

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



		September 30,		December 31,
		2010		2009

ASSETS

Current Assets:
Cash and cash equivalents		$	265,674	$	42,609
Accounts receivable less allowance for uncollectible accounts:
	2010 - $29,493; 2009 - $29,375		362,637		254,027
Materials, supplies and fuel, at average cost			64,795		69,176
Risk management assets (Note 6)			5,944		21,902
Intercompany income taxes receivable			10,356		10,356
Deferred income taxes			120,642		58,425
Other current assets			27,622		27,855
Total Current Assets			857,670		484,350

Utility Property:
Plant in service			7,500,812		7,414,432
Construction work-in-progress			861,231		627,026
Total			8,362,043		8,041,458
Less accumulated provision for depreciation			1,839,243		1,727,710
Total Utility Property, Net			6,522,800		6,313,748

Investments and other property, net			42,481		41,167

Deferred Charges and Other Assets:
Deferred energy (Note 3)			120,675		138,963
Regulatory assets			880,171		856,769
Regulatory asset for pension plans			124,016		129,709
Risk management assets (Note 6)			64		5,590
Other deferred charges and assets			111,420		126,075
Total Deferred Charges and Other Assets			1,236,346		1,257,106

TOTAL ASSETS		$	8,659,297	$	8,096,371

(Continued)

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


	September 30,			December 31,
	2010			2009

LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities:
Current maturities of long-term debt	$	356,538		$	119,474
Accounts payable		220,153			249,962
Accounts payable, affiliated companies		29,884			32,414
Accrued expenses		76,880			86,983
Risk management liabilities (Note 6)		38,593			39,122
Deferred energy (Note 3)		157,577			74,129
Other current liabilities		53,933			52,306
Total Current Liabilities		933,558			654,390

Long-term debt		3,546,724			3,535,440

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		953,645			794,890
Deferred investment tax credit		7,843			8,698
Accrued retirement benefits		26,358			39,678
Risk management liabilities (Note 6)		682			1,165
Regulatory liabilities		218,402			210,287
Other deferred credits and liabilities		202,410			201,784
Total Deferred Credits and Other Liabilities		1,409,340			1,256,502

Shareholder's Equity:
Common stock, $1.00 par value, 1,000 shares authorized, issued and outstanding for 2010 and 2009		1			1
Other paid-in capital		2,254,189			2,254,189
Retained earnings		518,931			399,345
Accumulated other comprehensive loss		(3,446	)		(3,496	)
Total Shareholder's Equity		2,769,675			2,650,039

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	8,659,297		$	8,096,371

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

(Concluded)

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



	For the Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	181,586		$	140,941
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		169,330			160,869
Deferred taxes and deferred investment tax credit		93,730			100,126
AFUDC-equity		(18,555	)		(16,558	)
Deferred energy		99,407			144,656
Amortization of other regulatory assets		41,415			41,791
Deferred rate increase		(6,250	)		(61,795	)
Other, net		3,085			5,507
Changes in certain assets and liabilities:
Accounts receivable		(108,609	)		(162,390	)
Materials, supplies and fuel		4,678			4,171
Other current assets		233			2,476
Accounts payable		27,249			3,323
Accrued retirement benefits		(13,320	)		(29,766	)
Other current liabilities		(8,474	)		(20,891	)
Risk management assets and liabilities		7,903			2,113
Other deferred assets		(2,214	)		(8,453	)
Other regulatory assets		(28,175	)		(42,348	)
Other deferred liabilities		(3,233	)		(30,079	)
Net Cash from Operating Activities		439,786			233,693

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(421,793	)		(517,985	)
Proceeds from sale of asset		3,254			-
Customer advances for construction		(3,891	)		(1,974	)
Contributions in aid of construction		42,034			42,561
Investments and other property - net		(99	)		(94	)
Net Cash used by Investing Activities		(380,495	)		(477,492	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		637,975			944,326
Retirement of long-term debt		(412,201	)		(628,837	)
Dividends paid		(62,000	)		(69,500	)
Net Cash from Financing Activities		163,774			245,989

Net Increase in Cash and Cash Equivalents		223,065			2,190
Beginning Balance in Cash and Cash Equivalents		42,609			28,594
Ending Balance in Cash and Cash Equivalents	$	265,674		$	30,784

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	180,732		$	171,955
Income taxes	$	2		$	2
Significant non-cash transactions:
Accrued construction expenses as of September 30,	$	57,638		$	69,842
Capital lease obligations incurred	$	15,336		$	-

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

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
OPERATING REVENUES:
Electric	$	239,284		$	265,734		$	653,416		$	734,386
Gas		19,286			19,745			139,711			132,686
Total Operating Revenues		258,570			285,479			793,127			867,072

OPERATING EXPENSES:
Fuel for power generation		66,133			89,125			181,232			229,119
Purchased power		33,545			25,580			110,262			92,439
Gas purchased for resale		10,823			11,269			101,536			101,457
Deferred energy - electric		9,964			26,646			17,189			68,222
Deferred energy - gas		1,795			2,286			7,646			1,923
Other operating expenses		39,490			38,843			118,450			123,748
Maintenance		7,419			8,173			26,770			23,939
Depreciation and amortization		26,848			27,545			79,737			80,043
Taxes other than income		6,330			6,162			18,494			17,046
Total Operating Expenses		202,347			235,629			661,316			737,936
OPERATING INCOME		56,223			49,850			131,811			129,136

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $698, $864, $1,586 and $2,364)		(16,983	)		(16,787	)		(51,141	)		(51,473	)
Interest income (expense) on regulatory items		(2,528	)		(2,047	)		(6,788	)		(3,764	)
AFUDC-equity		1,029			942			2,360			2,535
Other income		2,379			3,792			14,276			12,299
Other expense		(1,285	)		(813	)		(7,555	)		(4,601	)
Total Other Income (Expense)		(17,388	)		(14,913	)		(48,848	)		(45,004	)
Income Before Income Tax Expense		38,835			34,937			82,963			84,132

Income tax expense		14,373			10,671			30,066			25,926

NET INCOME	$	24,462		$	24,266		$	52,897		$	58,206

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

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


		September 30,		December 31,
		2010		2009

ASSETS

Current Assets:
Cash and cash equivalents		$	93,018	$	14,359
Accounts receivable less allowance for uncollectible accounts:
	2010 - $2,323; 2009 - $2,966		106,070		146,883
Materials, supplies and fuel, at average cost			53,709		54,802
Risk management assets (Note 6)			1,049		5,656
Intercompany income taxes receivable			10,351		19,315
Deferred income taxes			57,664		46,414
Other current assets			14,633		16,056
Total Current Assets			336,494		303,485

Utility Property:
Plant in service			3,489,982		3,419,190
Construction work-in-progress			103,417		89,102
Total			3,593,399		3,508,292
Less accumulated provision for depreciation			1,205,134		1,156,489
Total Utility Property, Net			2,388,265		2,351,803

Investments and other property, net			5,692		5,428

Deferred Charges and Other Assets:
Regulatory assets			351,400		362,009
Regulatory asset for pension plans			125,289		130,283
Risk management assets (Note 6)			-		1,142
Other deferred charges and assets			34,718		40,837
Total Deferred Charges and Other Assets			511,407		534,271

Assets Held for Sale (Note 10)			152,399		147,158

TOTAL ASSETS		$	3,394,257	$	3,342,145

(Continued)

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


	September 30,			December 31,
	2010			2009

LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities:
Current maturities of long-term debt	$	-		$	15,000
Accounts payable		76,357			76,867
Accounts payable, affiliated companies		19,678			21,091
Accrued expenses		35,332			34,185
Risk management liabilities (Note 6)		18,520			27,749
Deferred energy (Note 3)		150,312			117,276
Other current liabilities		15,401			14,996
Total Current Liabilities		315,600			307,164

Long-term debt		1,281,138			1,282,225

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		379,092			350,802
Deferred investment tax credit		12,542			13,843
Accrued retirement benefits		102,915			104,854
Risk management liabilities (Note 6)		233			1,068
Regulatory liabilities		192,053			175,732
Other deferred credits and liabilities		67,307			71,452
Total Deferred Credits and Other Liabilities		754,142			717,751

Liabilities Held for Sale (Note 10)		29,196			25,747

Shareholder's Equity:
Common stock, $3.75 par value, 20,000,000 shares authorized, 1,000 shares issued and outstanding for 2010 and 2009		4			4
Other paid-in capital		1,111,260			1,111,260
Retained earnings		(94,704	)		(99,601	)
Accumulated other comprehensive loss		(2,379	)		(2,405	)
Total Shareholder's Equity		1,014,181			1,009,258

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	3,394,257		$	3,342,145

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

(Concluded)

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

	For the Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	52,897		$	58,206
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		79,737			80,043
Deferred taxes and deferred investment tax credit		21,134			38,782
AFUDC-equity		(2,360	)		(2,535	)
Deferred energy		35,562			76,665
Gain on sale of asset		(7,575	)		-
Amortization of other regulatory assets		18,056			27,361
Other, net		4,454			(2,444	)
Changes in certain assets and liabilities:
Accounts receivable		51,221			59,312
Materials, supplies and fuel		1,184			(896	)
Other current assets		1,423			3,391
Accounts payable		1,112			(27,013	)
Accrued retirement benefits		(1,939	)		(7,545	)
Other current liabilities		1,615			2,285
Risk management assets and liabilities		2,183			1,062
Other deferred assets		(2,698	)		(2,796	)
Other regulatory assets		(13,504	)		(10,323	)
Other deferred liabilities		(2,691	)		(32,505	)
Net Cash from Operating Activities		239,811			261,050

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(111,476	)		(152,038	)
Proceeds from sale of asset		14,971			-
Customer advances for construction		(2,139	)		(4,035	)
Contributions in aid of construction		4,183			6,395
Investments and other property - net		(119	)		76
Net Cash used by Investing Activities		(94,580	)		(149,602	)

CASH FLOWS USED BY FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		22,736			329,324
Retirement of long-term debt		(41,308	)		(365,291	)
Investment by parent company		-			90,300
Dividends paid		(48,000	)		(128,800	)
Net Cash used by Financing Activities		(66,572	)		(74,467	)

Net Increase (Decrease) in Cash and Cash Equivalents		78,659			36,981
Beginning Balance in Cash and Cash Equivalents		14,359			21,411
Ending Balance in Cash and Cash Equivalents	$	93,018		$	58,392

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	48,990		$	50,387
Income taxes	$	12		$	12
Significant non-cash transactions:
Accrued construction expenses as of September 30,	$	7,525		$	6,164


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

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, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Pacific Energy Company, NVE Insurance Company, Inc. and Sierra Gas Holding Company. All intercompany balances and 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 2009 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the nine months ended September 30, 2010, are not necessarily indicative of the results to be expected for the full year.

Recent Accounting Standards Updates

Consolidations of VIEs

In June 2009, the FASB amended existing guidance related to the Consolidation of VIEs. NVE and the Utilities adopted this amendment on January 1, 2010. The amendment no longer allows the scope exception for contracts which an entity was unable to obtain financial information from to be excluded from the primary beneficiary determination. As a result, NVE and the Utilities will continually perform an analysis to determine whether their variable interests give it controlling financial interest in a VIE which would require consolidation. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the following characteristics: a) the power to direct the activities of a VIE 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 VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. To identify potential variable interests, management reviewed contracts under leases, long term purchase power contracts, tolling contracts and jointly owned facilities. The Utilities identified certain long-term purchase power contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary as defined above, as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. As of September 30, 2010, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.

Fair Value Measurements and Disclosures

In January 2010, the FASB amended the Fair Value Measurements and Disclosure Topic as reflected in the FASB Accounting Standards Codification for recurring and nonrecurring fair value measurements. NVE and the Utilities adopted this amendment on January 1, 2010. The new accounting guidance adds requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. In addition, the accounting update amends guidance on employers’ disclosures about postretirement benefit plan assets to require disclosures by classes of assets instead of by major categories of assets. The amendment is effective for NVE and the Utilities as of January 1, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in Level 3 fair value measurements. Those disclosures will be effective for NVE and the Utilities as of January 1, 2011. The adoption of this guidance did not have, nor is expected to have, a significant impact on the disclosure requirements for NVE and the Utilities.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC. 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 information includes amounts 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, 2010	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	872,986	$	239,284	$	19,286	$	258,570	$	5		$	1,131,561

Energy Costs:
Fuel for power generation		181,100		66,133		-		66,133		-			247,233
Purchased power		216,309		33,545		-		33,545		-			249,854
Gas purchased for resale		-		-		10,823		10,823		-			10,823
Deferred energy - net		22,296		9,964		1,795		11,759		-			34,055
	$	419,705	$	109,642	$	12,618	$	122,260	$	-		$	541,965

Gross Margin	$	453,281	$	129,642	$	6,668	$	136,310	$	5		$	589,596

Other operating expense		75,798						39,490		975			116,263
Maintenance		15,707						7,419		-			23,126
Depreciation and amortization		56,575						26,848		-			83,423
Taxes other than income		9,038						6,330		52			15,420

Operating Income (Loss)	$	296,163					$	56,223	$	(1,022	)	$	351,364

Nine months ended	NPC		SPPC		SPPC		SPPC		NVE			NVE
September 30, 2010	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	1,840,745	$	653,416	$	139,711	$	793,127	$	19		$	2,633,891

Energy Costs:
Fuel for power generation		469,282		181,232		-		181,232		-			650,514
Purchased power		412,276		110,262		-		110,262		-			522,538
Gas purchased for resale		-		-		101,536		101,536		-			101,536
Deferred energy - net		81,719		17,189		7,646		24,835		-			106,554
	$	963,277	$	308,683	$	109,182	$	417,865	$	-		$	1,381,142

Gross Margin	$	877,468	$	344,733	$	30,529	$	375,262	$	19		$	1,252,749

Other operating expense		208,374						118,450		2,611			329,435
Maintenance		50,945						26,770		-			77,715
Depreciation and amortization		169,330						79,737		-			249,067
Taxes other than income		28,857						18,494		181			47,532

Operating Income (Loss)	$	419,962					$	131,811	$	(2,773	)	$	549,000

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 - 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 operating expense		68,521						38,843		628			107,992
Maintenance		12,014						8,173		-			20,187
Depreciation and amortization		54,996						27,545		-			82,541
Taxes other than income		8,970						6,162		45			15,177

Operating Income (Loss)	$	292,900					$	49,850	$	(665	)	$	342,085

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 - 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 operating expense		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 other than income		26,394						17,046		137			43,577

Operating Income (Loss)	$	351,493					$	129,136	$	(2,148	)	$	478,481

NOTE 3. REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy amounts were included in the consolidated balance sheets as of September 30, 2010 (dollars in thousands):

	September 30, 2010
Description	NPC Electric				SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance authorized in 2010 DEAA	$	(102,398	)	(1)	$	(100,625	)	$	(17,041	)	$	(220,064	)
2010 Amortization		-				15,927			5,880			21,807
2010 Deferred Energy Over Collections (2)		(70,027	)			(39,280	)		(15,173	)		(124,480	)
Nevada Deferred Energy Balance at September 30, 2010 - Subtotal	$	(172,425	)		$	(123,978	)	$	(26,334	)	$	(322,737	)
Cumulative CPUC balance (2)		-				(1,684	)		-			(1,684	)
Reinstatement of deferred energy (effective 6/07, 10 years)		135,523				-			-			135,523

Total	$	(36,902	)		$	(125,662	)	$	(26,334	)	$	(188,898	)

Deferred Assets
Deferred energy		120,675				-			-			120,675
Current Liabilities
Deferred energy		(157,577	)			(123,978	)		(26,334	)		(307,889	)
Liabilities held for sale (3)		-				(1,684	)		-			(1,684	)
Total	$	(36,902	)		$	(125,662	)	$	(26,334	)	$	(188,898	)

(1)	Refer to NPC DEAA under “Settled Regulatory Actions” below for separate discussion regarding rate offset of this balance.
(2)	These deferred energy over collections will be filed in March 2011 DEAA filings.
(3)	Refer to Note 10, Assets Held For Sale.

Pending Regulatory Actions

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. The CPUC held hearings in June 2010 and in October 2010 issued a decision approving the transaction. Separately in December 2009, SPPC filed an application with the PUCN requesting PUCN approval of the transaction. In July 2010, SPPC filed certain components of the transaction under its IRP process and requested consolidation with the previously filed a pplication. A decision from the PUCN is expected in December 2010. See Note 10, Assets Held for Sale.

SPPC Electric GRC

In June 2010, SPPC filed its statutorily required GRC for its Nevada electric operations. In this GRC filing, SPPC requested the following:

●	Increase in general rates by $29.3 million, approximately a 3.87% increase;
●	ROE and ROR of 10.75% and 8.14%, respectively;
●	Authorization to recover new electric and common plant additions along with ordinary changes in operating expense, maintenance expense and administrative and general costs;
●	Authorization to amortize $8.4 million of development costs associated with the postponed EEC over six years and to defer $5.1 million for recovery until management’s final decision on how to proceed with the development of the EEC is determined.

If approved, the new rates would be effective January 1, 2011. Hearings have begun and are expected to conclude in early November 2010.

SPPC Gas GRC

In June 2010, SPPC filed a GRC for its gas operations. In this GRC, SPPC is requesting the following:

●	Increase in general rates by $4.3 million, approximately a 2.64% increase;
●	ROE and ROR of 10.75% and 5.48%, respectively;
●	Authorization to recover new gas and common plant additions along with ordinary changes in operating expense, maintenance expense and administrative and general costs.

If approved, the new rates would be effective January 1, 2011. Hearings have begun and are expected to conclude in early November 2010.

Settled Regulatory Actions

Nevada Power Company

NPC DEAA

In March 2010, NPC filed an application to create a new DEAA rate. In its application, NPC requested to refund $102 million of deferred fuel and purchased power costs. Separately, NPC filed a petition to offset the NPC DEAA over collection (credit balance) of $102 million against the deferred BTGR debit balance of $95.8 million. The BTGR debit balance of $95.8 million was a result of NPC’s 2008 GRC, which granted NPC approval to defer billings of its rate increase from July 1, 2009 to December 31, 2009 in a regulatory asset for which NPC recognized revenues for in 2009. Reference NPC’s 2008 GRC in Note 3, Regulatory Actions, of the Notes to Financial Statements of the 2009 Form 10-K for additional information. The PUCN consolidated both dockets for hearing purposes.

In September 2010, the PUCN accepted a stipulation for the DEAA and BTGR offset applications, which will result in an overall revenue decrease of $9.2 million or 0.41% for the period October 1, 2010 through December 31, 2011.

Sierra Pacific Power Company

SPPC Nevada Gas DEAA

In March 2010, SPPC filed an application to create a new DEAA rate. In September, the PUCN accepted a stipulation to decrease rates by $8.3 million, a decrease of 4.69%, while refunding approximately $17 million of deferred gas costs. The new DEAA rate became effective October 1, 2010.

SPPC Nevada Electric DEAA

In March 2010, SPPC filed an application to create a new DEAA rate. In September, the PUCN accepted a stipulation to decrease rates by $47.0 million, a decrease of 6.31%, while refunding $101 million of deferred fuel and purchased power costs. The new DEAA rate became effective October 1, 2010.

Utilities

Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)

EEIR

In 2009, the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation. The regulation was adopted by the Legislature on July 22, 2010. The Utilities will account for the effects of such regulation in accordance with FASC 980-605-25, Alternative Revenue Programs. Accordingly, as of August 1, 2010, the Utilities are recording the amount of additional revenues which are objectively determinable and probable of recovery and are attributable to reduced kWh sales related to our energy efficiency programs, prior to their inclusion in rates. As of September 30, 2010, NPC and SPPC recorded revenues of approximately $5.8 million and $3.1 million, respectively, with an offset to a regulatory asset for this program. In March 2011, the Utilities will file an additional rate case to clear the accumulated regulatory asset account between August 1, 2010 and December 31, 2010, with rates effective in October 2011. Additionally, in October 2010, the Utilities filed to set base rates beginning April 1, 2011 to recover approximately $35.1 million and $7.6 million for NPC and SPPC, respectively, for estimated reduced kWh sales related to our energy efficiency programs in 2011. Annually, thereafter, the Utilities will file a rate case in March, to adjust rates and set a clearing rate or EEIR for over or under collected balances, effective in October of the same year.

EEPR

In addition, the regulation approved the transition of the recovery of DSM program costs from general rates (filed every 3 years) to recovery through independent annual rate filings. Accordingly, in their filing made in October 2010, the Utilities have requested to set base rates beginning April 1, 2011 to recover the cost of implementing DSM program costs of approximately $70.6 million and $12.1 million for NPC and SPPC, respectively. Costs accumulated between August 1, 2010 and December 31, 2010 will be requested for recovery in the March 2011 filing with rates effective October 2011. Thereafter, annual filings will be made in March with rates effective October of the same year. Beginning August 1, 2010, the Utilities will net total DSM program costs with the DSM Base Rate recovery o r EEPR and record the differential to a regulatory asset account and corresponding offset to expense. However, as ordered by the PUCN, and since there will be no EEPR until April 1, 2011, all DSM program costs will continue to be accumulated in a regulatory asset account. The new regulation will permit a more timely recovery of revenues to offset the expense of implementing demand side management programs.

NOTE 4. LONG-TERM DEBT

As of September 30, 2010, 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
2010	$	(287	)	$	-	$	-	$	(287	)
2011		368,454			-		-		368,454
2012		134,822			100,000		63,670		298,492
2013		105,405			250,000		-		355,405
2014		128,513			-		230,039		358,552
		736,907			350,000		293,709		1,380,616
Thereafter		3,178,355			916,417		191,500		4,286,272
		3,915,262			1,266,417		485,209		5,666,888
Unamortized Premium (Discount) Amount		(12,000	)		14,721		336		3,057
Total	$	3,903,262		$	1,281,138	$	485,545	$	5,669,945

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

NPC

General and Refunding Mortgage Notes, Series X

On September 14, 2010, NPC issued and sold $250 million of its 5.375% General and Refunding Mortgage Notes, Series X, due 2040. Of the approximately $247 million in net proceeds, $231 million was used on October 14, 2010 to redeem (i) approximately $206 million in the aggregate principal amount of fixed rate unsecured tax-exempt local furnishing (“two-county”) bonds issued for NPC’s benefit and (ii) approximately $20 million unsecured tax-exempt pollution control refunding revenue bonds issued for NPC’s benefit. The remaining net proceeds of approximately $16 million were used to repay amounts outstanding under NPC’s revolving credit facility.

$600 Million Revolving Credit Facility

In April 2010, NPC terminated its $589 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $600 million secured revolving credit facility, maturing in April 2013. The fees on the $600 million revolving credit facility for the unused portion and on the amounts borrowed have increased from the prior facility reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, N.A. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rati ng by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $600 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the availability under the revolving credit facility to NPC shall in no event be less than 50% of the total commitments there under. The calculation of NPC’s negative mark-to-market exposure as of August 31, 2010 was approximately $51.8 m illion, which amount was in effect for borrowings under the credit facility during the month of September 2010.

The NPC Credit Agreement contains one financial maintenance covenant that 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. In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

SPPC

$250 Million Revolving Credit Facility

In April 2010, SPPC terminated its $332 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $250 million secured revolving credit facility, maturing in April 2013. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have increased from the prior facility reflecting current market conditions. The Administrative Agent for the facility is Bank of America, N.A. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon SPPC’s credit rating b y S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the availability under the revolving credit facility to SPPC shall in no event be less than 50% of the total commitments there under. The calculation of SPPC’s negative mark-to-market exposure as of August 31, 2010 was approximately $ 22.5 million, which amount was in effect for borrowings under the credit facility during the month of September 2010.

The SPPC Credit Agreement contains one financial maintenance covenant that 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. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC’s senior se cured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The September 30, 2010 carrying amount of cash and cash equivalents, current assets and current liabilities 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, 2010, 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 $5.6 billion as of December 31, 2009.

The total fair value of NPC’s consolidated long-term debt at September 30, 2010, 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 $3.7 billion at December 31, 2009.

The total fair value of SPPC’s consolidated long-term debt at September 30, 2010, 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, 2009.

NOTE 6. DERIVATIVES AND HEDGING ACTIVITIES

NVE, NPC and SPPC 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 account ing and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value.

Commodity Risk

The energy supply function encompasses the reliable and efficient operation of the Utilities’ generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. 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 m itigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

Interest Rate Risk

In 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, 2010, 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.

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):

	September 30, 2010						December 31, 2009
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	3.6	$	2.6	$	1.0	$	11.9	$	9.2	$	2.7
Non-Current		0.1		0.1		-		1.9		1.4		0.5
Total	$	3.7	$	2.7	$	1.0	$	13.8	$	10.6	$	3.2

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, which as of September 30, 2010, 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. Due to regulatory accounting treatment under which the utilities operate, 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 (dollars in millions):

	September 30, 2010									December 31, 2009
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current (1)	$	3.4		$	3.4		$	-		$	15.7		$	12.7		$	3.0
Risk management assets- noncurrent		-			-			-			4.8			4.2			0.6
Total risk management assets		3.4			3.4			-			20.5			16.9			3.6

Risk management liabilities- current		57.1			38.6			18.5			66.9			39.1			27.8
Risk management liabilities- noncurrent		0.9			0.7			0.2			2.2			1.1			1.1
Total risk management liabilities		58.0			39.3			18.7			69.1			40.2			28.9

Risk management regulatory assets/liabilities – net (2)	$	(54.6	)	$	(35.9	)	$	(18.7	)	$	(48.6	)	$	(23.3	)	$	(25.3	)

(1)

Included in Risk management assets – current at September 30, 2010, is a $ 3.4 million cumulative gain for interest rate swaps 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. For the nine months ended September 30, 2010, NVE and NPC would have recorded a cumulative loss of $6.0 million, and $12.6 million, respectively; and SPPC would have recorded a cumulative gain of $6.6 million. For the three months ended September 30, 2010, NVE, NPC and SPPC would have recorded gains of $18.7 million, $17.1 million and $1.6 million, respectively. However, as permitted 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 decreased as of September 30, 2010 as compared to December 31, 2009, due to settlements of derivative contracts and lower natural gas prices relative to contract prices and natural gas prices at December 31, 2009.

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

	September 30, 2010						December 31, 2009
	Commodity Volume (MMBTU)						Commodity Volume (MMBTU)
	NVE		NPC		SPPC		NVE		NPC		SPPC

Commodity volume assets- current		-		-		-		47.1		40.7		6.4
Commodity volume assets- noncurrent		-		-		-		10.3		7.6		2.7
Total commodity volume of assets(1)		-		-		-		57.4		48.3		9.1

Commodity volume liabilities- current		33.4		23.8		9.6		51.7		32.7		19.0
Commodity volume liabilities- noncurrent		0.6		0.5		0.1		7.8		5.3		2.5
Total commodity volume of liabilities		34.0		24.3		9.7		59.5		38.0		21.5

(1)	The change in commodity volumes of assets and liabilities at September 30, 2010, as compared to December 31, 2009, is primarily due to the suspension of the Utilities’ hedging program as of October 2009. As such, the Utilities’ exposure to mark-to-market hedging transactions has declined.

NOTE 7. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension and other postretirement plan covering substantially all employees of NVE and the Utilities. NVE allocates the unfunded liability and net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location. A summary of the components of net periodic pension and other postretirement costs for the nine months ended September 30 follows. This summary is based on a December 31, measurement date (dollars in thousands):

NVE, consolidated

	Pension Benefits						Other Postretirement Benefits
	For the three months ended September 30,						For the three months ended September 30,
	2010			2009			2010			2009

Service cost	$	4,727		$	4,709		$	617		$	577
Interest cost		10,718			11,036			2,184			2,637
Expected return on plan assets		(11,069	)		(9,290	)		(1,556	)		(1,508	)
Amortization of prior service cost		(448	)		(448	)		(972	)		(171	)
Amortization of net loss		3,777			6,894			1,085			1,273
Settlement loss		-			-			-			84

Net periodic benefit cost	$	7,705		$	12,901		$	1,358		$	2,892

	Pension Benefits						Other Postretirement Benefits
	For the nine months ended September 30,						For the nine months ended September 30,
	2010			2009			2010			2009

Service cost	$	14,182		$	14,128		$	1,850		$	1,732
Interest cost		32,154			33,109			6,551			7,912
Expected return on plan assets		(33,206	)		(27,870	)		(4,667	)		(4,525	)
Amortization of prior service cost		(1,345	)		(1,345	)		(2,917	)		(514	)
Amortization of net loss		11,329			20,681			3,256			3,818
Settlement loss		-			-			-			254

Net periodic benefit cost	$	23,114		$	38,703		$	4,073		$	8,677

The average percentage of NVE net periodic costs capitalized during 2010 and 2009 was 33.85% and 36.91%, respectively.

NPC

	Pension Benefits						Other Postretirement Benefits
	For the three months ended September 30,						For the three months ended September 30,
	2010			2009			2010			2009

Service cost	$	2,392		$	2,393		$	353		$	310
Interest cost		5,023			5,270			619			607
Expected return on plan assets		(5,362	)		(4,462	)		(567	)		(509	)
Amortization of prior service cost		(433	)		(433	)		236			289
Amortization of net loss		1,764			3,298			300			287
Settlement loss		-			-			-			19

Net periodic benefit cost	$	3,384		$	6,066		$	941		$	1,003

	Pension Benefits						Other Postretirement Benefits
	For the nine months ended September 30,						For the nine months ended September 30,
	2010			2009			2010			2009

Service cost	$	7,175		$	7,179		$	1,060		$	931
Interest cost		15,069			15,809			1,856			1,820
Expected return on plan assets		(16,085	)		(13,385	)		(1,702	)		(1,528	)
Amortization of prior service cost		(1,300	)		(1,300	)		709			868
Amortization of net loss		5,292			9,894			899			861
Settlement loss		-			-			-			57

Net periodic benefit cost	$	10,151		$	18,197		$	2,822		$	3,009

The average percentage of NVE net periodic costs capitalized during 2010 and 2009 was 36.34% and 39.79%, respectively.

SPPC

	Pension Benefits						Other Postretirement Benefits
	For the three months ended September 30,						For the three months ended September 30,
	2010			2009			2010			2009

Service cost	$	2,004		$	2,061		$	245		$	251
Interest cost		5,389			5,471			1,547			2,014
Expected return on plan assets		(5,431	)		(4,580	)		(961	)		(977	)
Amortization of prior service cost		(26	)		(26	)		(1,213	)		(465	)
Amortization of net loss		1,969			3,425			777			978
Settlement loss		-			-			-			65

Net periodic benefit cost	$	3,905		$	6,351		$	395		$	1,866

	Pension Benefits						Other Postretirement Benefits
	For the nine months ended September 30,						For the nine months ended September 30,
	2010			2009			2010			2009

Service cost	$	6,012		$	6,184		$	733		$	755
Interest cost		16,167			16,414			4,640			6,041
Expected return on plan assets		(16,292	)		(13,741	)		(2,883	)		(2,932	)
Amortization of prior service cost		(78	)		(78	)		(3,638	)		(1,394	)
Amortization of net loss		5,907			10,276			2,332			2,934
Settlement loss		-			-			-			195

Net periodic benefit cost	$	11,716		$	19,055		$	1,184		$	5,599

The average percentage of NVE net periodic costs capitalized during 2010 and 2009 was 34.57% and 36.53%, respectively.

During the nine months ended September 30, 2010, the company made contributions to the pension plan totaling $30 million, which were allocated to the 2010 plan year. At the present time, it is anticipated that additional funding will be required for both the pension and other postretirement benefits plans in 2010 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006; however, the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution. Currently, NVE expects to fund an additional $10 million to the pension plan in 2010.

In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act of 2010. One feature of this legislation is the elimination of the tax deductibility of employer health care costs for retiree prescription drug expenses that are reimbursed as part of the Medicare Part D federal subsidy. NVE has not participated in the subsidy program since 2008, and therefore does not expect any significant impact on its financial statements as a result of this legislation.

In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law. This legislation permits employers to choose between alternative amortization methods for shortfalls due to losses in asset market values. The legislation is designed to reduce contributions to defined benefit pension plans by allowing them to be spread over a longer period of time. NVE is currently evaluating the options and impact of this legislation, but does not believe it would need to avail itself of the benefits under this Act. The estimated future contributions shown above do not take into account any possible impacts of this legislation.

NOTE 8. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

During the nine months ended September 30, 2010, NVE and the Utilities entered into significant contracts which increased commitments as disclosed in the Form 10-K.

	2010		2011		2012		2013		2014		Thereafter		Total
Purchased Power - NPC(1)	$	-	$	169	$	49,383	$	57,181	$	118,312	$	4,213,645	$	4,438,690
Transportation - NPC (2)	$	4,700	$	24,700	$	30,400	$	80,649	$	92,149	$	938,710	$	1,171,308
Transportation - SPPC (2)	$	900	$	20,000	$	20,500	$	23,098	$	23,598	$	49,406	$	137,502
Coal - NPC(3)	$	-	$	20,311	$	33,886	$	33,882	$	34,402	$	182,466	$	304,947
Long-Term Service Agreements - NPC(4)	$	3,378	$	11,367	$	12,040	$	12,143	$	11,415	$	80,951	$	131,294
Long-Term Service Agreement – SPPC(4)	$	225	$	4,562	$	4,770	$	4,567	$	5,091	$	27,820	$	47,035
Capital Projects (5)	$	125,000	$	-	$	-	$	-	$	-	$	-	$	125,000

(1)	Represents estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver energy.
(2)	Included in transportation is the TUA with GBT, of which NPC will be responsible for 95% and SPPC 5%, and is contingent upon certain conditions, final construction costs and reaching commercial operation, which is expected in late 2012, and other material transportation contracts.
(3)	Includes a 10 year long term agreement for the purchase of coal.
(4)	Amounts calculated based on estimated usage.
(5)	Represents the Utilities' aggregate 25% share in the estimated $500 million On Line project, of which NPC will be responsible for 95% and SPPC 5%.

Environmental

NPC

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.

SPPC

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 completed its response to the EPA in December 2009 and will continue to monitor developments relating to this Section 114 request. SPPC cannot predict the impact, if any, associated with this info rmation 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 2009 Form 10-K, NPC was subject to various environmental proceedings which were settled as of December 31, 2009. NPC continues to comply with these environmental commitments. As of September 30, 2010, environmental expenditures did not change materially from those disclosed in the 2009 Form 10-K.

Litigation Contingencies

NPC and SPPC

Peabody Western Coal Company Royalty Claim

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 (SCE) prior to the time it became non-operational on December 31, 2005.

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 SCE in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

The Navajo Joint Owners were first served in the Missouri lawsuit in January 2005. The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners. 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 Generating Station and the Mohave Generating Station. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. Initially, the DC Lawsuit sought $600 million in damages, treble damages and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action had been stayed since October, 2004 until March, 2008, when the U.S. District Court lifted the stay. On April 12, 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages. The Court ordered substantial completion of factual discovery by the fourth quarter of 2010. Management cannot predict the timing or outcome of a decision on this matter.

SPPC

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, alternatively SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

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

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

NOTE 9. EARNINGS PER SHARE (NVE)

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

		Three Months Ended September 30,				Nine Months Ended September 30,
		2010		2009		2010		2009
Basic EPS
Numerator ($000)

	Net income	$	182,746	$	182,646	$	217,971	$	178,785

Denominator (1)
	Weighted average number of common shares outstanding		235,117,058		234,629,761		234,991,208		234,479,605

Per Share Amounts

	Net income per share - basic	$	0.78	$	0.78	$	0.93	$	0.76

Diluted EPS
Numerator ($000)

	Net income	$	182,746	$	182,646	$	217,971	$	178,785

Denominator (1)
	Weighted average number of shares outstanding before dilution		235,117,058		234,629,761		234,991,208		234,479,605
	Stock options		35,973		37,132		30,818		23,983
	Non-Employee Director stock plan		147,718		104,609		137,032		94,900
	Employee stock purchase plan		9,463		10,058		6,186		8,247
	Restricted Shares		87,613		13,307		69,322		9,542
	Performance Shares		1,079,362		574,052		902,159		409,277
			236,477,187		235,368,919		236,136,725		235,025,554

Per Share Amounts

	Net income per share - diluted	$	0.77	$	0.78	$	0.92	$	0.76

(1)

The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for all periods. If the conditions for conversion were met under this plan, 701,190 and 707,950 shares would be included for the three and nine months ended September 30, 2010, respectively, and 731,505 and 850,596 shares would be included for the three and nine months ended September 30, 2009, respectively.

NOTE 10. ASSETS HELD FOR SALE

Sale of California Electric Distribution and Generation Assets

In April 2009, SPPC entered into an agreement to sell its California electric distribution and generation assets to CalPeco. In connection with the sale of the assets, SPPC entered into a separate five year purchase power agreement to sell energy to CalPeco, contingent upon the completion of the sale of the assets. 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. Depending on certain closing adjustments, such proceeds are expected to be at or near current book value of the related net assets. Net rate base assets include utility plant in service, net and deferred credits and other liabilities. The sale is expected to close in the fourth quarter of 2010 and has been approved by the U.S. Department of Justice, the FERC and the CPUC. The PUCN is expected to rule on the sale in December 2010.

In accordance with FASB presentation accounting guidance for discontinued operations, ASC 205-10-20, the California asset sale met the “assets held for sale” criteria, but, did not meet the “component-of-an-entity” criteria. The California electric distribution and generation assets held for sale do not have cash flows that can be clearly distinguished operationally from the rest of the entity because they do not operate individually, but rather as a part of SPPC’s whole operating system, which includes all of the electric distribution and generation assets owned by SPPC.

Below are the major classes of assets and liabilities held for sale and presented in the consolidated balance sheets as of September 30, 2010 and December 31, 2009 (dollars in millions):

Assets	September 30, 2010		December 31, 2009

Utility Plant in Service	$	194.3	$	188.6
Less: Accumulated depreciation		54.5		55.4
Utility Plant in Service, net		139.8		133.2
CWIP		5.5		4.6
Other current assets		7.1		8.6
Deferred Charges		-		0.8

Assets Held for Sale	$	152.4	$	147.2

Liabilities
Deferred Credits and Other Liabilities	$	29.2	$	25.7
Liabilities Held for Sale	$	29.2	$	25.7

Sale of Independence Lake

In May 2010, SPPC sold a lake and surrounding property located in the State of California, known as Independence Lake, for approximately $15 million. The gain on sale was approximately $14.7 million before taxes; however, approximately $7.1 million of the gain has been deferred as a regulatory liability and will be paid to SPPC’s ratepayers over approximately three years.

NOTE 11. SHAREHOLDERS’ EQUITY

Changes in Shareholders’ Equity

The following tables represent year-to-date changes in shareholders’ equity of NVE, NPC and SPPC (in thousands):

NVE
	Number of Common Shares Issued		Common Shareholders’ Equity

Balance at December 31, 2009		234,834	$	3,223,922
Net Income		-		217,971
Accumulated Other Comprehensive Income		-		94
Common Stock Issued		339		339
Common Stock Dividends Declared		-		(77,561	)
Stock Purchase and Dividend Reinvestment		-		2,009
Other		-		1,740
Balance at September 30, 2010		235,173	$	3,368,514

Balance at December 31, 2008		234,317	$	3,131,186
Net Income		-		178,785
Accumulated Other Comprehensive Income		-		81
Common Stock Issued		366		366
Common Stock Dividends Declared		-		(70,401	)
Stock Purchase and Dividend Reinvestment		-		1,863
Other		-		1,940
Balance at September 30, 2009		234,683	$	3,243,820

NPC
	Number of Common Shares Issued		Common Shareholder’s Equity

Balance at December 31, 2009		1	$	2,650,039
Net Income		-		181,586
Accumulated Other Comprehensive Income		-		50
Common Stock Dividends Declared		-		(62,000	)
Balance at September 30, 2010		1	$	2,769,675

Balance at December 31, 2008		1	$	2,627,567
Net Income		-		140,941
Accumulated Other Comprehensive Income		-		36
Common Stock Dividends Declared		-		(77,000	)
Other		-		7
Balance at September 30, 2009		1	$	2,691,551

SPPC
	Number of Common Shares Issued		Common Shareholder’s Equity

Balance at December 31, 2009		4	$	1,009,258
Net Income		-		52,897
Accumulated Other Comprehensive Income		-		26
Common Stock Dividends Declared		-		(48,000	)
Balance at September 30, 2010		4	$	1,014,181

Balance at December 31, 2008		4	$	877,961

Net Income		-		58,206
Accumulated Other Comprehensive Income		-		28
Common Stock Dividends Declared		-		(32,000	)
Capital Contribution from Parent		-		90,300
Balance at September 30, 2009		4	$	994,495

Dividends

The following dividend declarations were made by the BOD of NVE:

Declaration Date	Amount	Payable Date	Shareholders of Record Date

May 4, 2010	$0.11 per share	June 16, 2010	June 1, 2010
August 5, 2010	$0.11 per share	September 22, 2010	September 7, 2010
October 28, 2010	$0.12 per share	December 22, 2010	December 7, 2010

NPC and SPPC paid dividends to NVE of $62 million and $48 million, respectively, for the nine months ended September 30, 2010. NPC and SPPC declared an additional dividend to NVE on October 28, 2010, of $12 million and $60 million, respectively.

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 growth, 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, increased unemployment, and energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)

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;

(4)

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;

(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, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

(6)

unseasonable or severe weather, drought, threat of wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, 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;

(7)	whether the Utilities can procure and/or obtain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada;

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

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

(10)

whether on remand to the Nevada State Engineer after the Nevada Supreme Court’s June 17, 2010, decision on rehearing in Great Basin Water Network, et al. v. Nevada State Engineer, a decision could be made to re-open certain permitted water rights of the Southern Nevada Water Authority, which are used to supply water to the Utilities' power production plants and service territories, which could adversely impact the operations of those plants and future growth and customer usage patterns;

(11)	whether the Utilities will be able to integrate the new advanced metering system with their billing and other computer information systems and whether the technologies and equipment will perform as expected, and in all other respects, meet operational, commercial and regulatory requirements;

(12)

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;

(13)

explosions, fires, accidents and mechanical breakdowns that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;

(14)

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;

(15)	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;

(16)

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;

(17)	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;

(18)

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; including the impact of acts of terrorism or vandalism that damage or disrupt information technology and systems owned by the Utilities, or third parties on which the Utilities rely;

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

(20)	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;

(21)

changes in the business of the Utilities’ major customers engaged in gold mining or gaming, including availability and cost of capital or power demands, 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

(22)	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.

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 and distribution of natural gas. Other 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 $182.7 million for the three months ended September 30, 2010 compared to net income of $182.6 million for the same period in 2009. NVE recognized net income of $218.0 million for the nine months ended September 30, 2010 compared to net income of $178.8 million for the same period in 2009. The increase in net income for the three months ended September 30, 2010 compared to the same period in 2009 is primarily due to an increase in gross margin, for which a primary component is attributable to revenue recorded for reduced kWh sales related to our energy efficiency programs, as discussed in Note 3, Regulatory “Actions of the Condensed Notes to Financial Statements, and an increase in AFUDC. This increase was partially offset by higher income taxes as a result of a lower tax effective rate in 2009, and increased operating and maintenance expense. The increase in net income for the nine months ended September 30, 2010 compared to the same period in 2009 is primarily due to increased rates as a result of NPC’s GRC, which was effective beginning July 1, 2009 and a decrease in other operating expenses, maintenance expense and interest expense, partially offset by higher income taxes as a result of a lower tax effective rate in 2009 and an increase in interest expense on regulatory items, primarily as a result of over-collected deferred energy balances.

The Utilities are regulated by the PUCN and, for the California electric service territory 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 generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale 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’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage due to varying weather, customer growth 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 t he operating and financial performance of the Utilities. Additionally, the timely recovery of purchased power and fuel costs, and other costs, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2010 and Beyond Objectives and Challenges

For the remainder of 2010 and in 2011, management’s key objectives will remain focused on executing its three-part strategy of energy efficiency and conservation programs for its customers, purchase and development of renewable energy projects and construction of generating facilities and expansion of transmission capability. A key objective in 2010 was to obtain PUCN approval of NPC’s IRP and to file SPPC’s IRP. NPC received approval of its IRP and SPPC filed its IRP in July 2010. The approval of NPC’s IRP enables it to move forward with the three-part strategy by increasing the dollars spent on DSM projects, implementing the ASD initiative, now known as the NV Energize project, and constructing the ON Line transmission line, which will connect the northern and southern service area and a lso provide greater access to renewable energy resources. See more discussion of NPC’s IRP approval under Other Significant Matters. However, due to the economic uncertainty in Nevada, NVE’s execution of the three-part strategy will be a significant challenge. Another challenge will be to further broaden our access to capital to fund the three-part strategy and maintain sufficient liquidity.

Economic Conditions

Although the economy in the U.S. is starting to show signs of recovery from the recession, Nevada continues to struggle. As of September 2010, the unemployment rate in Nevada was 14.4%. However, as of July 2010, taxable sales have increased 5.3% from the prior year, visitor volume increased by 2.0% compared to August 2009 and gaming revenues increased 11.5% compared to August 2009; however, the increase in revenues may be attributable to the timing of certain conventions from September to August in 2010, as compared to 2009.

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. As of September 2010, unemployment in the Las Vegas area was 15%. In addition to employment, management continues to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas as signs of future growth in customers and customer usage. As of August 2010, the hotel/motel occupancy rate in Las Vegas was 82%, an increase of 0.6% from a year ago. In 2010, room growth is expected to increase to 1.2% and then slow to 0.1% in 2011. The increase in room growth for 2010 is primarily due to the Cosmopolitan Resort & Casino, which is expected to add approximately 2,000 room s to Las Vegas. 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. As of August 2010, compared to the same period in 2009, in Southern Nevada, construction activity, another leading indicator, has seen a decrease in the number of residential permits while commercial permits have remained relatively flat.

SPPC’s service territory, which consists primarily of Washoe County, has also been affected by the recessionary environment. Unemployment in Washoe County was at 13.6% as of September 2010, up from 11.7% a year ago. However taxable sales increased 2.9% compared to a year ago July 2009, while gaming revenues decreased 3.1% compared to a year ago August 2009.

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.

As the Utilities’ service territories continue to be economically challenged, management will continue to place a significant emphasis on evaluating the foregoing economic indicators and their effect on various interrelated factors including, but not limited to:

●	customer growth;
●	customer usage;
●	revenues;
●	load factors;
●	future capital projects and capital requirements;
●	managing operating and maintenance expenses within projected revenue growth without compromising safety, reliability and efficiency;
●	our liquidity and ability to access capital markets;
●	collections on accounts receivable;
●	counterparty risk; and
●	workforce reduction.

Management cannot predict when economic recovery may commence in Nevada, but expects that the Nevada economy will continue to struggle for the next several years. As such, a significant challenge for us will be to manage costs, while remaining steadfast in carrying out our 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. In response to this challenge, the three part strategy will become more focused on projects that will allow us to leverage existing assets, improve transmission capabilities which are necessary for the Utilities to meet their Portfolio Standard, discussed below, further deve lop the NV Energize initiative, which will allow us to reduce our cost structure and future capital expenditures, and effectively contain capital and operating costs. Effective capital and operating cost containment began during 2009 by the reduction and delay of capital expenditures and implementation of severance programs as discussed further in Note 17, Severance Programs, of the Notes to Financial Statements in the 2009 Form 10-K.

General Economic Information

The general economic data, on both national and local levels, contained in this quarterly report are based on independent government and industry publications, reports by market research firms or other independent published sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to the accuracy thereof.

Three Part Strategy

Beginning in 2007, NVE embarked on a three part energy supply strategy to manage resources against our load by encouraging energy efficiency and conservation programs, the purchase and development of renewable energy projects, the

construction of generating facilities in an effort to reduce our reliance on purchased power, and expansion of transmission capability.

Energy Efficiency and Conservation Programs

Over the past two years, the Utilities invested approximately $120 million in energy efficiency and conservation. NPC’s IRP, which was approved in July 2010, includes various DSM programs to increase energy efficiency and conservation programs totaling approximately $209.9 million over a three year period.

In addition, NVE has been awarded a $138 million grant in stimulus funding from the DOE specifically for NVE’s $301 million NV Energize project. The NV Energize project will provide NVE with the Smart Grid infrastructure necessary to enable widespread use of smart meters, enabling customers to more directly manage their energy usage. NV Energize involves the deployment of a delivery mechanism that creates a new, more advanced infrastructure for NVE’s demand response and energy efficiency and conservation programs.

The agreement between NVE and the DOE was signed in March 2010. As a result of executing the contract, the Utilities have begun a pilot program with the ultimate goal of completing the installation of approximately 1.5 million smart meters throughout the entire state of Nevada by 2012, making Nevada one of the first states to implement a statewide Smart Grid Plan.

In July 2010, NPC received PUCN approval for the NV Energize project for approximately $95 million. SPPC’s investment of $50 million was submitted in its IRP filing in July 2010. An additional $2 million within NVE’s capital budget covers energy management system upgrades in 2010.

Purchase and Development of Renewable Energy Projects

NPC is currently completing construction of the Goodsprings 6 MW recovered energy project at its budgeted cost of $22 million. The Goodsprings project was given IRP approval by the PUCN in 2008. In 2009, NPC received PUCN approval to purchase the output from three geothermal plants expanded by 32 MW, an additional 49 MW of output from two new solar projects, and a landfill gas project to be completed in 2010/2011. In 2010, the Utilities will continue development of these renewable energy projects, conduct additional requests for proposals for renewable energy, and explore other opportunities to add to their supplies of renewable energy and associated PECs.

During the first quarter of 2010, NPC submitted seven long-term renewable energy PPAs to the PUCN for approval. The seven contracts include two solar projects totaling 160 MW, three geothermal projects totaling 130 MW, one wind project totaling 150 MW and one landfill gas project with a capacity of 3 MW. Together the projects total 443 MW. These projects were approved by the PUCN in July 2010.

In addition, two short-term renewable energy PPAs were entered into. One was signed in December 2009 with renewable energy deliveries commencing at that time and the other agreement was signed in February 2010 with deliveries commencing in April 2010.

In April 2010, NPC and SPPC filed their joint Annual Compliance Report with the PUCN. SPPC reported that it met the Portfolio Standard for total PECs and the solar requirements of the Portfolio Standard. NPC reported that it met the solar requirement of the Portfolio Standard, but did not meet the Portfolio Standard requirement for total PECs. In October 2010, the PUCN approved a stipulation that allows NPC to offset its 2009 PEC shortfall with credits earned in 2010 and a loan of surplus credits from SPPC.

Construction of Generating Facilities and Expansion of Transmission Capabilities

NPC will continue the construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011. In addition, the Utilities will continue to optimize the operations of their existing generating assets.

In NPC’s IRP filed in February 2010 and SPPC’s 8th Amendment to its 2007 IRP filed in March 2010, the Utilities requested approval of ON Line, a 500 kV transmission line from the proposed Robinson Summit Substation near Ely, Nevada to the existing Harry Allen Substation located northeast of Las Vegas, Nevada at an aggregate cost of approximately $500 million. The preferred plan was a joint ownership proposal (“Joint Project”) of ON Line among NPC, SPPC and GBT, an affiliate of LS Power. The Utilities had entered into a Memorandum of Understanding and Term Sheet (“MOU”) for the Joint Project that contemplates two phases of development. The alternative to the Joint Project, also filed in NPC’s IRP an d SPPC’s 8th Amendment to its 2007 IRP, is for the Utilities’ to self build ON Line. In addition to connecting NVE’s northern service territory with its service territory in southern Nevada, ON Line would also provide access to isolated renewable energy resources in parts of northern and eastern Nevada, which would further advance the Utilities’ ability in meeting its Portfolio Standard, discussed above.

As part of NPC’s IRP approval, the PUCN granted the Utilities’ request to move forward with construction of ON Line through the Joint Project with GBT. The PUCN’s approval was conditioned upon there being no material changes in the language of the final Transmission Use and Capacity Exchange Agreement (“TUA”) between the parties from that in the MOU that was

previously filed with the PUCN. The PUCN also accepted the Utilities’ alternative to proceed with the self-build option, if the Utilities cannot reach an agreement with GBT.

In August 2010, the Utilities and GBT finalized the TUA which is not substantially different from the MOU. Pursuant to the terms of the Agreement, NPC will own an undivided 23.75% interest in ON Line, SPPC will own an undivided 1.25% interest in ON Line and GBT will own an undivided 75% interest in ON Line. The Agreement provides that the Utilities will make a monthly payment to GBT for an initial term of 41 years, and, in return, the Utilities will be entitled to use all of the capacity of ON Line. Further, if GBT constructs certain interconnecting transmission lines north or south of ON Line, the Utilities and GBT have agreed to exchange capacity between ON Line and such interconnecting transmission lines based on the a mounts of their respective investments. The estimated construction cost of ON Line is approximately $500 million, of which the Utilities will be responsible for funding their aggregate 25% share. The Utilities will be primarily responsible for overseeing construction of ON Line, and for the operation and maintenance of ON Line upon its completion. The Utilities’ obligation to fund their 25% share of construction costs is subject to several customary conditions precedent, including, but not limited to, obtaining approvals from the PUCN and the FERC and GBT securing sufficient financing for the project. The parties expect these conditions to be satisfied on or before December 31, 2010.

Additional key objectives include management of energy risk, environmental matters, and regulatory filings, and to further broaden access to capital.

Further Broaden Access to Capital

A significant focus for the remainder of 2010 will continue to be 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. Maintaining or improving the Utilities’ credit ratings will be essential to negotiating favorable financing terms, and will continue to be a significant focus for the remainder of 2010. Significant amounts of capital may be necessary to fund prospective construction projects, as discussed further under NVE’s Liquidity and Capital Resources in the 2009 Form 10-K and as a result of the approval of NPC’s IRP. Additionally, 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 delay capital expenditures. Management may be required to meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and/or the issuance of equity by NVE. As such, the ability to issue new debt or equity securities on favorable terms will be a significant focus for the remainder of 2010. In April 2010, NPC and SPPC entered into new revolving credit facilities for $600 million and $250 million, respectively, which expire in April 2013 to replace their credit facilities which were set to expire in November 2010. Additionally in September 2010, NPC issued $250 million of its 5.375% General and Refunding Mortgage Notes, Series X.

Other Significant Matters

Regulatory Environment

NPC 2009 IRP

On February 1, 2010, NPC refiled its 2009 triennial IRP. In July 2010, the PUCN issued its order which included the following significant items:

●	Approval to jointly develop with GBT (an affiliate of LS Power), the ON Line, which is a 500 kV transmission line from the proposed Robinson Summit Substation near Ely, Nevada to the existing Harry Allen Substation located northeast of Las Vegas, Nevada at a cost of approximately $500 million. The PUCN also accepted NPC’s alternative to proceed with the self build option for ON Line, if the Utilities cannot reach an agreement with GBT;
●	Granted NPC’s request for critical facility designation for its investment in the ON Line;
●	Approval of the NV Energize project of approximately $95 million which includes NPC and SPPC successfully obtaining a grant of $138 million in federal funds from the DOE to co-fund the project. This project will allow customers to control their energy use by providing transparent and timely consumption and pricing information and energy control capabilities while facilitating and enhancing the companies’ existing and planned demand response programs and other energy conservation and efficiency measures;
●	Approval to establish a regulatory asset for stranded non-advanced metering infrastructure electric meter costs related to the NV Energize project;
●	Approval of various DSM programs to increase energy efficiency and conservation programs totaling approximately $209.9 million over the three year action plan;
●	Approval of seven renewable energy long term power purchase agreements;
●	Approval of NPC’s proposal to postpone the EEC indefinitely, but ordered NPC to resubmit the request as a part of its next triennial IRP filing in July 2012; and
●	Approval of the long-term load forecast and the three-year forecast.

Legislative Changes

In 2009 the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover revenue attributable to reduced kWh sales related to our energy efficiency programs. In June 2010, the PUCN adopted the regulations. As of August 1, 2010, the Utilities began recording revenues for this program. See Note 3, Regulatory Actions of Condensed Notes to Financial Statements for further details.

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 of interest costs for both the nine months ended September 30, 2010 and 2009, respectively.

As of September 30, 2010, NPC had paid $62.0 million in dividends to NVE and SPPC had paid $48.0 million in dividends to NVE.

On October 28, 2010, NPC and SPPC declared dividends to NVE of $12 million and $60 million, respectively.

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 increased during the nine months ended September 30, 2010, compared to the same period in 2009, 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 increased revenues as a result of the rate increase in NPC’s GRC offset by BTER rate reductions. Also contributing to the increase were a decrease in funding for pension plans, reduced spending for conservation programs and other regulated activities, higher payments to vendors in 2009 and a refund to a transmission customer in 2009.

Cash Used By Investing Activities. Cash used by investing activities decreased mainly due to the slowdown in construction for infrastructure and due to the sale of property.

Cash From Financing Activities. Cash from financing activities decreased due to a reduction in draws on the revolving credit facility partially offset by higher dividend payments.

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 outcomes and economic conditions.

Available Liquidity as of September 30, 2010 (in millions)
	NVE		NPC			SPPC
Cash and Cash Equivalents	$	19.6	$	265.7	(1)	$	93.0
Balance available on Revolving Credit Facilities (2)		N/A		485.3			234.1
Less reduction for hedging obligations (3)				(51.8	)		(22.5	)
	$	19.6	$	699.2		$	304.6

(1)	NPC balance reflects remaining proceeds from the issuance of the G&R Series X Notes on September 14, 2010. These proceeds were used to redeem approximately $226 million of tax-exempt debt on October 14, 2010. (See NPC’s Financing Transactions).
(2)	As of October 27, 2010, NPC and SPPC had approximately $487 million and $215.3 million available under their revolving credit facilities, which includes reductions in availability for hedging transactions and letters of credits, as discussed further under NPC’s and SPPC’s Financing Transactions.
(3)	Reduction for hedging obligations reflect balances as of August 31, 2010.

NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. treasury bills, or bank deposits. 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 their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NVE and the Utilities have no significant debt maturities in 2010. Significant debt maturities in 2011 are limited to NPC’s $350 million 8.25% General and Refunding Notes, Series A, which mature on June 1, 2011. As of October 27, 2010, NPC has borrowed approximately $60 million on its $600 million revolving credit facility, and SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

NVE and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities. In order to fund long-term capital requirements, including maturing debt, NVE and the Utilities will likely use a combination of internally generated funds, the Utilities’ revolving credit facilities, the issuance of long-term debt and/or equity and in the case of the Utilities capital contributions from NVE. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel, purchased power and operating costs in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral a s discussed below under Gas Supplier Matters, 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 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’ utilization of their revolving credit facilities may be limited.

The Utilities’ credit ratings on their senior secured debt remain at investment grade (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.

As of October 27, 2010, NVE has approximately $2.5 million payable of debt service obligations remaining for 2010, which it intends to pay through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries below).

NVE designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

NVE’s contractual obligations changed from that reported in the 2009 Form 10-K for the following significant items: (i) the TUA with GBT with respect to the ON Line project; (ii) the Utilities’ new revolving credit facilities entered into in April 2010; (iii) NPC's $250 million of 5.375% General and Refunding Mortgage Notes, Series X, due 2040, as discussed under Financing Transactions for their respective sections; and (iv) several other commitments as detailed in Note 11, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of September 30, 2010, NVE (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $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 its 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, 2010, NVE, NPC, SPPC and their subsidiaries had approximately $5.7 billion of debt and other obligations outstanding, consisting of approximately $3.9 billion of debt at NPC, approximately $1.3 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 for as long as the debt remains investment grade rated 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 FER C 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.

Credit Ratings

The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt. NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. In May 2010, Fitch upgraded the ratings for NVE and the Utilities. The rating for NVE’s senior unsecured debt was upgraded to BB from BB-. The rating for the Utilities’ senior secured debt was upgraded to BBB from BBB- and the senior unsecured debt of NPC t o BB+ from BB. The rating outlook was revised from positive to stable. As of September 30, 2010, 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, Moody’s and Fitch’s rating outlooks for NVE, NPC and SPPC are Stable.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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, 2010 for all suppliers continuing to provide power under a WSPP agreement would approximate a $50.0 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 Condensed 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. 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 in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry fo rward mark-to-market exposure.

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. As of September 30, 2010, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $30.6 million. Of this amount, approxim ately $22.9 million would be required if NPC’s Senior Unsecured ratings are downgraded from their current level and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

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. As discussed under NPC’s and SPPC’s Financing Transactions, the Utilities shall reduce their availability under the Utilities’ revolving credit facilities for negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities. The calculation of NPC’s and SPPC’s negative mark-to-market exposure as of August 31, 2010 was approximately $51.8 million and $22.5 million, respectively, which amount wa s in effect for borrowings during the month of September 2010. Currently, the Utilities only have hedging contracts with counterparties who are also lenders on the revolving credit facilities; however, future contracts entered into with non-lenders may require the Utilities to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, the Utilities have suspended their hedging program, and as such, expect their exposure to negative mark-to-market hedging transactions to decline.

Ability to Issue Debt

NV Energy, Inc.

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, 2010, NVE (consolidated) would be allowed to incur up to $1.8 billion 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 this restriction, 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, 2010, the combined total outstanding indebtedness and letters of credit under their respective revolving credit facilities was approximately $130.6 million not including any reductions for negative mark-to-market transactions. See NPC’s and SPPC’s Ability to Issue Debt sections for further discussion of the Utilities’ limitations on ability to issue debt.

If the applicable series of 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).

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.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of approximately $164.1 million during the three months ended September 30, 2010, compared to net income of approximately $163.6 million for the same period in 2009. During the nine months ended September 30, 2010, NPC recognized net income of approximately $181.6 million compared to net income of approximately $140.9 million for the same period in 2009.

During the nine months ended September 30, 2010, NPC paid $62.0 million in dividends to NVE. On October 28, 2010, NPC declared an additional dividend to NVE of approximately $12 million.

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is 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. 0; Gross margin changes based on such factors as general base rate adjustments (which are required by statute to be filed every three years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2010		2009		Prior Year %			2010		2009		Prior Year %

Operating Revenues:	$	872,986	$	933,520		-6.5	%	$	1,840,745	$	1,945,818		-5.4	%


Energy Costs:
Fuel for power generation		181,100		160,960		12.5	%		469,282		455,355		3.1	%
Purchased power		216,309		288,248		-25.0	%		412,276		541,746		-23.9	%
Deferred energy		22,296		46,911		-52.5	%		81,719		144,910		-43.6	%
	$	419,705	$	496,119		-15.4	%	$	963,277	$	1,142,011		-15.7	%


Gross Margin	$	453,281	$	437,401		3.6	%	$	877,468	$	803,807		9.2	%

Gross margin increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to revenue attributable to reduced kWh sales related to our energy efficiency programs, which became effective August 1, 2010 (see Note 3, Regulatory Actions in the Condensed Notes to Financial Statements). Also contributing to the increase in gross margin was an increase in revenue associated with the REPR. REPR is, as a rate mechanism, designed to provide rebates to customers for the implementation of approved renewable projects. REPR revenues are offset by the amortization of these costs in other operating expense and therefore have no effect on net income. Further contributing to the increase in gross margin is an increase in demand during peak periods for commercial and industrial customers, and to a lesser extent, slight customer growth. Partially offsetting the increase was a change in customer usage patterns which may be attributable to economic conditions, conservation programs and decreased transmission revenue.

Gross margin increased for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to an increase in BTGR revenue as a result of NPC’s 2008 GRC effective July 1, 2009, and revenue attributable to reduced kWh sales related to our energy efficiency programs, which became effective August 1, 2010 (see Note 3, Regulatory Actions in the Condensed Notes to Financial Statements). Partially offsetting the increase was a change in customer usage patterns which may be attributable to economic conditions and conservation programs, unusually cool weather, decreased transmission revenue, as well as decreased REPR revenue; however, as stated above, REPR revenues are offset in other operating expense and have no effect o n net income.

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

Operating Revenue

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2010		2009		Prior Year %			2010		2009		Prior Year %
Operating Revenues:
Residential	$	460,535	$	484,561		-5.0	%	$	899,423	$	939,488		-4.3	%
Commercial		132,176		148,504		-11.0	%		340,258		365,595		-6.9	%
Industrial		262,129		278,728		-6.0	%		550,518		578,661		-4.9	%
Retail revenues		854,840		911,793		-6.2	%		1,790,199		1,883,744		-5.0	%
Other		18,146		21,727		-16.5	%		50,546		62,074		-18.6	%
Total Operating Revenues	$	872,986	$	933,520		-6.5	%	$	1,840,745	$	1,945,818		-5.4	%

Retail sales in thousands of MWhs		7,208		7,197		0.2	%		16,255		16,626		-2.2	%

Average retail revenue per MWh	$	118.60	$	126.69		-6.4	%	$	110.13	$	113.30		-2.8	%

NPC’s retail revenues decreased for the three months ended September 30, 2010, as compared to the same period in 2009 primarily due to decreased energy rates from NPC’s various BTER quarterly updates and the expiration of the Western Energy Crisis Amortization rate (See Note 3, Regulatory Actions of the Condensed Notes to the Financial Statements and in the 2009 Form 10-K). The decrease in revenue was partially offset by an increase in demand charges for commercial and industrial customers, and an increase in revenue attributable to reduced kWh sales related to our energy efficiency programs, which became effective August 1, 2010. Slight customer growth and increased residential usage due to hotter weather also offset the decrease in re venue. The average number of Residential, Commercial and Industrial customers increased by 0.7%, 0.2% and 1.5%, respectively, compared to the same period in the prior year.

NPC’s retail revenues decreased for the nine months ended September 30, 2010, as compared to the same period in 2009.

●	Residential retail revenue decreased primarily due to decreased customer usage in the second quarter resulting from lower May 2010 temperatures as compared to hotter than normal weather in May 2009. Decreased energy rates from NPC’s various BTER quarterly updates and the expiration of the Western Energy Crisis Amortization rate also contributed to the decrease in revenue. These decreases were partially offset by increases in general rates as a result of NPC’s 2008 GRC, effective July 1, 2009, (See Note 3, Regulatory Actions of the Condensed Notes to the Financial Statements and in the 2009 Form 10-K) and revenue attributable to reduced kWh sales related to our energy efficiency programs, as discussed above. The average number of Residential customers increased by 0.2% compar ed to the same period in the prior year.

●	Commercial and Industrial retail revenues decreased primarily due to decreased rates. Energy rates decreased as a result of NPC’s various BTER quarterly cases, the expiration of the Western Energy Crisis Amortization rate, and decreased winter general rates as a result of NPC’s 2008 GRC effective July 1, 2009. (See Note 3, Regulatory Actions of the Condensed Notes to the Financial Statements and in the 2009 Form 10-K). Decreased customer usage in the second quarter resulting from lower May 2010 temperatures as compared to hotter than normal weather in May 2009 also contributed to the decrease in revenue. These decreases were partially offset by an increase in demand charges for commercial and industrial customers, and as a result of revenue attributable to reduced kWh sales related to our energy e fficiency programs, as discussed above. The average number of Commercial and Industrial customers increased by 0.8% and 0.4%, respectively, compared to the same period in the prior year.

Electric Operating Revenues – Other decreased for the three and nine months ended September 30, 2010, compared to the same period in 2009. The decrease is primarily due to the expiration of a significant transmission agreement with Calpine Energy Services and decreases in sales for resale.

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
●		Volatility of commodity prices

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2010		2009		Prior Year %			2010		2009		Prior Year %

Energy Costs
Fuel for Generation	$	181,100	$	160,960		12.5	%	$	469,282	$	455,355		3.1	%
Purchased Power		216,309		288,248		-25.0	%		412,276		541,746		-23.9	%
Energy Costs	$	397,409	$	449,208		-11.5	%	$	881,558	$	997,101		-11.6	%

MWhs
MWhs Generated (in thousands)		4,738		4,999		-5.2	%		11,868		12,688		-6.5	%
Purchased Power (in thousands)		2,804		2,553		9.8	%		5,211		5,345		-2.5	%
Total MWhs		7,542		7,552		-0.1	%		17,079		18,033		-5.3	%

Average cost per MWh
Average fuel cost per MWh of Generated Power	$	38.22	$	32.20		18.7	%	$	39.54	$	35.89		10.2	%
Average cost per MWh of Purchased Power	$	77.14	$	112.91		-31.7	%	$	79.12	$	101.36		-21.9	%
Average total cost per MWh	$	52.69	$	59.48		-11.4	%	$	51.62	$	55.29		-6.6	%

Energy Costs decreased for the three and nine months ended September 30, 2010, compared to the same period in 2009 primarily due to a decrease in hedging costs and a decrease in total system demand, partially offset by higher natural gas prices. Volume for the nine months ended September 30, 2010 decreased primarily due to cooler weather. The average cost per MWh for energy costs decreased primarily due to decreased hedging costs.

●	Fuel for generation costs increased for the three and nine months ended September 30, 2010 primarily due to higher cost of natural gas and the change in method of allocating electric tolling option expense between fuel for generation and purchased power which had no impact on gross margin or operating income, partially offset by the decrease in volume and a decrease in hedging costs. Volume decreased for the nine months ended September 30, 2010 due primarily to outages within internal generation in the early part of the year. The average cost per MWh increased for the three and nine months due to an increase in natural gas costs and the change in method of allocating electric tolling option expense, partially offset by a decrease in hedging costs.

●	Purchased power costs and the average cost per MWh decreased for the three and nine months ended September 30, 2010 primarily due to a decrease in hedging costs and the change in method of allocating hedging costs to purchased power electric tolling option, as discussed above, partially offset by an increase in renewable energy purchases. MWhs increased as a result of the outages discussed above.

Deferred Energy

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %

Deferred energy	$	22,296	$	46,911		-52.5	%	$	81,719	$	144,910		-43.6	%

Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended September 30, 2010 and 2009 include amortization of deferred energy of $5.3 million and $14.7 million, respectively; and an over-collection of amounts recoverable in rates of $17.0 million and $32.2 million, respectively. Amounts for the nine months ended September 30, 2010 and 2009 include amortization of deferred energy of $20.7 million and $33.5 million, respectively; and an over-collection of amounts recoverable in rates of $61.0 million and $111.4 million, respectively. 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 2009 Form 10-K.

Other Operating Expenses

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %

Other operating expense	$	75,798	$	68,521		10.6	%	$	208,374	$	206,771		0.8	%
Maintenance expense	$	15,707	$	12,014		30.7	%	$	50,945	$	58,280		-12.6	%
Depreciation and amortization	$	56,575	$	54,996		2.9	%	$	169,330	$	160,869		5.3	%

Other operating expense increased for the three and nine months ended September 30, 2010, compared to the same period in 2009, primarily due to external consulting fees, leases, and increases in amortization of REPR costs; however, as discussed under Gross Margin, REPR costs do not have an effect on net income. These increases were partially offset by lower employee pension and benefit expenses.

Maintenance expense increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to a 2010 planned major outage at the Silverhawk Generating Station and maintenance at the Higgins, Reid Gardner, Navajo and Lenzie Generating Stations.

Maintenance expense decreased for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to planned maintenance outages that occurred in 2009 at the Clark and Reid Gardner Generating Stations. This decrease was partially offset by maintenance at the Higgins, Navajo and Harry Allen Generating Stations.

Depreciation and amortization increased for the three and nine months ended September 30, 2010, compared to the same period in 2009, primarily due to a general increase in plant-in-service and the addition of transmission and distribution infrastructure.

Interest Expense

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %

Interest expense (net of AFUDC-debt: $5,787, $2,815, $15,763, $13,483)	$	54,144	$	58,355		-7.2	%	$	161,496	$	170,535		-5.3	%

Interest expense decreased for the three and nine months ended September 30, 2010 compared to the same period in 2009 primarily due to the increase in AFUDC due to the construction of the Harry Allen Generating Station and the expiration in 2009 of amortization costs related to debt issues and redemptions. Also contributing to the decrease in interest expense was lower interest on variable rate debt and the partial redemption of Series 1997A in December 2009.

Partially offsetting this decrease were higher credit facility balances in 2010, and increased interest expense due to the issuance of $500 million, Series V, General and Refunding Mortgage Notes in March 2009 and the issuance of $250 million, Series X, General and Refunding Mortgage Notes in September 2010.

Other Income (Expense)

	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			Change from Prior Year %			2010			2009			Change from Prior Year %

Interest Income (expense) on regulatory items	$	(1,157	)	$	248			-566.5	%	$	(1,965	)	$	2,891			-168.0	%
AFUDC-equity	$	6,795		$	3,385			100.7	%	$	18,555		$	16,558			12.1	%
Other income	$	3,842		$	3,776			1.7	%	$	9,084		$	18,726			-51.5	%
Other expense	$	(3,034	)	$	(1,537	)		97.4	%	$	(9,338	)	$	(12,335	)		-24.3	%

The change in interest income (expense) on regulatory items for the three and nine months ended September 30, 2010, compared to the same period in 2009, is primarily due to over-collected deferred energy balances. See Note 3, Regulatory Actions, for further details of deferred energy balances.

AFUDC-equity increased for the three and nine months ended September 30, 2010, compared to the same period in 2009, primarily due to construction at the Harry Allen Generating Station, partially offset by completion of the Southern Operations Center in June 2009 and various construction projects.

Other income increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to higher carrying charges for energy conservation programs in 2010. These were partially offset by interest income received on income tax refunds in 2009.

Other income decreased for the nine months ended September 30, 2010, compared to the same period in 2009, due to the settlement of outstanding legal matters in 2009 associated with the Natural Gas Provider case, as discussed further in Note 13, Commitments and Contingencies of the Notes to Financial Statements in the 2009 Form 10-K, interest income received on income tax refunds in 2009, and lower carrying charges for energy conservation programs in 2010 due to a portion which is now included in the BTGR rate.

Other expense increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to an adjustment for deferred energy settlement in 2010. Other expense decreased for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to charges in 2009 resulting from NPC’s GRC in 2009, and the write-off of permitting costs in 2009, partially offset by adjustments for the settlement of the deferred energy rate case, see Note 3, Regulatory Actions for further details.

ANALYSIS OF CASH FLOWS

Cash flows increased during the nine months ended September 30, 2010, compared to the same period in 2009, due to an increase in cash from operating activities and a reduction in cash used for 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 increased revenues as a result of the rate increase in NPC’s 2008 GRC offset by BTER rate reductions, a decrease in funding for pension plans, reduced spending for conservation programs and other regulated activities, higher payments to vendors in 2009 and a refund to a transmission customer in 2009.

Cash Used By Investing Activities. Cash used by investing activities decreased mainly due to the slowdown in construction for infrastructure.

Cash From Financing Activities. Cash from financing activities decreased primarily due to a reduction in draws on the revolving credit facility, partially offset by slightly lower dividend payments to NVE.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

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

Available Liquidity as of September 30, 2010 (in millions)
	NPC
Cash and Cash Equivalents	$	265.7	(1)
Balance available on Revolving Credit Facility (2)		485.3
- Less reduction for hedging obligations (3)		(51.8	)
	$	699.2

(1)	Balance reflects remaining proceeds from the issuance of the G&R Series X Notes on September 14, 2010. These proceeds were used to redeem approximately $226 million of tax-exempt debt on October 14, 2010. (See NPC’s Financing Transactions).
(2)	As of October 27, 2010, NPC had approximately $487 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.
(3)	Reduction for hedging obligations reflects balances as of August 31, 2010.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills and bank deposits. 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 has no significant debt maturities in 2010. NPC’s significant debt maturities in 2011 are limited to its $350 million 8.25% General and Refunding Notes, Series A, which mature on June 1, 2011. As of October 27, 2010, NPC has borrowed approximately $60 million on its $600 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including recovery of deferred energy, and the use of its revolving credit facility. Furthermore, in order to fund long-term capital requirements, including maturing debt, NPC will likely use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE. 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, 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.

During the nine months ended September 30, 2010, NPC paid dividends to NVE of approximately $62 million.

NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

NPC’s contractual obligations changed from that reported in the 2009 Form 10-K for the following significant items: (i) the TUA with GBT with respect to the ON Line project; (ii) NPC’s new revolving credit facility entered into in April 2010; (iii) NPC’s $250 million of 5.375% General and Refunding Mortgage Notes, Series X, due 2040, as discussed under Financing Transactions; and (iv) several other commitments as detailed in Note 11, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Financing Transactions

General and Refunding Mortgage Notes, Series X

$600 Million Revolving Credit Facility

In April 2010, NPC terminated its $589 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $600 million secured revolving credit facility, maturing in April 2013. The fees on the $600 million revolving credit facility for the unused portion and on the amounts borrowed have increased from the prior facility reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, National Association (formerly Wachovia Bank, National Association). The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $600 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the availability under the revolving credit facility to NPC shall not be less than 50% of the total commitments there under.

The NPC Credit Agreement contains one financial maintenance covenant that 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. In the event that NPC did not meet the financial maintenance covenant or there is an event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit un der the facility. In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

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, 2010, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $500 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, 2010, NPC has financing authority from the PUCN for the period ending December 31, 2010, consisting of authority (1) to issue additional long-term debt securities of up to $750 million; (2) to refinance up to approximately $471 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.

However, on June 30, 2010, NPC filed a financing application with the PUCN, seeking a three-year extension to the authority set to expire in 2010, and requesting new authority to refinance an additional $480 million of long-term debt securities. On October 14, 2010 the PUCN issued an order authorizing NPC to restate and utilize its available authority, and granting new refinancing authority in the amount of $480 million of long-term debt securities, expiring on December 31, 2013.

As a result of the order and following the issuance of $250 million of its Series X G&R Bonds on September 14, 2010, and the redemption of approximately $226 million of NPC’s two-county bonds on October 14, 2010 (See Financing Transactions), as of October 29, 2010, NPC’s financing authority consists of (1) additional long-term debt securities of $725 million; and (2) refinancing authority up to $672.5 million. In addition, NPC’s ongoing authority to maintain a revolving credit facility up to $1.3 billion has not changed.

b.	Financial covenants within NPC’s financing agreements – As stated in Financing Transactions above, NPC’s revolving credit facility agreement, dated November 2005, has been replaced with a new $600 million revolving credit agreement. Under the $600 million revolving credit facility, NPC must 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. Based on September 30, 2010 financial statements, NPC was in compliance with this covenant and could incur up to $2.0 billion of additional indebtedness.

	All other financial covenants contained in NPC’s 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 additional covenants; and

c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.8 billion.

Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2010, $4.2 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $631.4 million of additional General and Refunding Mortgage Securities as of September 30, 2010. 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 the Indenture.

Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under its credit facility, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt. NPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. In May 2010, Fitch upgraded the ratings for NPC’s senior secured debt to BBB from BBB- and the senior unsecured debt to BB+ from BB, and revised the rating outlook from positive to stable. As of September 30, 2010, 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

S&P’s, Moody’s and Fitch’s rating outlooks for NPC are Stable.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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 follo wing 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, 2010 for all suppliers continuing to provide power under a WSPP agreement would approximate a $50.0 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 Condensed 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. 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 in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward ma rk-to-market exposure.

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. As of September 30, 2010, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $30.6 million. Of this amount, approxim ately $22.9 million would be required if NPC’s Senior Unsecured ratings are downgraded from their current level and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

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. As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is

reduced by the amount of negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. The calculation of NPC’s negative mark-to-market exposure as of August 31, 2010 was approximately $51.8 million, which amount was in effect for borrowings during the month of September 2010. Currently, NPC only has hedging contracts with counterparties who are also lenders on the revolving credit facility; however, future contracts entered into with non-lenders may require NPC to post cash collateral in the event of a credit rating downgrade. Finally, a s of October 2009, NPC has suspended its hedging program as such expect its exposure to negative mark-to-market positions to decline.

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 its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $24.5 million for the three months ended September 30, 2010, compared to net income of $24.3 million for the same period in 2009. During the nine months ended September 30, 2010, SPPC recognized net income of approximately $52.9 million compared to $58.2 million for the same period in 2009.

During the nine months ended September 30, 2010, SPPC paid $48 million in dividends to NVE. On October 28, 2010, SPPC declared an additional dividend to NVE of approximately $60 million.

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

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less 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 S tatements. 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
	2010		2009		Prior Year %			2010		2009		Prior Year %
Operating Revenues:
Electric	$	239,284	$	265,734		-10.0	%	$	653,416	$	734,386		-11.0	%
Gas		19,286		19,745		-2.3	%		139,711		132,686		5.3	%
	$	258,570	$	285,479		-9.4	%	$	793,127	$	867,072		-8.5	%

Energy Costs:
Fuel for power generation	$	66,133	$	89,125		-25.8	%	$	181,232	$	229,119		-20.9	%
Purchased power		33,545		25,580		31.1	%		110,262		92,439		19.3	%
Gas purchased for resale		10,823		11,269		-4.0	%		101,536		101,457		0.1	%
Deferred energy-electric		9,964		26,646		-62.6	%		17,189		68,222		-74.8	%
Deferred energy-gas		1,795		2,286		-21.5	%		7,646		1,923		297.6	%
	$	122,260	$	154,906		-21.1	%	$	417,865	$	493,160		-15.3	%

Energy Costs by Segment:
Electric	$	109,642	$	141,351		-22.4	%	$	308,683	$	389,780		-20.8	%
Gas		12,618		13,555		-6.9	%		109,182		103,380		5.6	%
	$	122,260	$	154,906		-21.1	%	$	417,865	$	493,160		-15.3	%

Gross Margin by Segment:
Electric	$	129,642	$	124,383		4.2	%	$	344,733	$	344,606		0.0	%
Gas		6,668		6,190		7.7	%		30,529		29,306		4.2	%
	$	136,310	$	130,573		4.4	%	$	375,262	$	373,912		0.4	%

Electric gross margin increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1999-1 and revenue attributable to reduced kWh sales related to our energy efficiency programs, which became effective August 1, 2010 (see Note 3, Regulatory Actions in the Condensed Notes to Financial Statements). Also contributing to the increase in gross margin was an increase in revenue associated with REPR; however, REPR revenues are offset by the amortization of these costs in other operating expense and therefore have no effect on net income. Partially offsetting the increase was cooler weather and a change in customer usage patterns which may be attributable to economic conditions and conservation programs.

Electric gross margin increased slightly for the nine months ended September 30, 2010, compared to the same period in 2009 primarily due to an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1999-1 and revenue attributable to reduced kWh sales related to our energy efficiency programs, which became effective August 1, 2010, (see Note 3, Regulatory Actions in the Condensed Notes to Financial Statements). Partially offsetting the increase was cooler weather and a change in customer usage patterns which may be attributable to economic conditions and conservation programs and a decrease in REPR revenues; however, as stated above, REPR revenues are offset in other operating expense and have no effect on net income.

Gas gross margin increased for the three and nine months ended September 30, 2010, compared to the same period in 2009, primarily due to increased customer usage as a result of colder weather.

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

Electric Operating Revenue

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from Prior Year %							Change from Prior Year %
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %
Electric operating revenues:
Residential	$	82,146	$	93,594		-12.2	%	$	235,668	$	263,287		-10.5	%
Commercial		93 ,785		108,167		-13.3	%		252,402		296,671		-14.9	%
Industrial		51,738		56,328		-8.1	%		139,200		151,671		-8.2	%
Retail revenues		227,669		258,089		-11.8	%		627,270		711,629		-11.9	%
Other		11,615		7,645		51.9	%		26,146		22,757		14.9	%
Total revenues	$	239,284	$	265,734		-10.0	%	$	653,416	$	734,386		-11.0	%

Retail sales in thousands
of megawatt-hours (MWh)		2,192		2,206		-0.6	%		6,075		6,128		-0.9	%

Average retail revenue per MWh	$	103.86	$	116.99		-11.2	%	$	103.25	$	116.13		-11.1	%

SPPC’s retail revenues decreased for the three and nine months ended September 30, 2010 as compared to the same period in 2009, primarily due to decreases in retail rates as a result of SPPC’s various BTER quarterly updates and the annual Deferred Energy case effective October 1, 2009. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K. These decreases were partially offset by increased industrial usage primarily due to a gold mining customer which resumed operations in October 2009 and revenues attributable to reduced kWh sales related to our energy efficiency programs, which became effective August 1, 2010. For the three months ended September 30, 2010, the average number of residential, commercial, and industrial customers increased 0.3%, 0.4%, and 0.2%, respectively. For the nine months ended September 30, 2010, the average number of residential and commercial customers increased 0.1% and 0.2%, respectively, while the industrial customers decreased 1.2%.

Electric Operating Revenues – Other increased for the three and nine months ended September 30, 2010 primarily due to an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Revenue Redemption Bonds.

Gas Operating Revenues

	Three Months							Nine Months
	Ended September 30,							Ended September 30,
					Change from							Change from
	2010		2009		Prior Year %			2010		2009		Prior Year %
Gas operating revenues:
Residential	$	9,953	$	10,740		-7.3	%	$	72,699	$	74,410		-2.3	%
Commercial		4,617		4,913		-6.0	%		34,014		35,191		-3.3	%
Industrial		1,784		2,155		-17.2	%		11,228		11,779		-4.7	%
Retail revenues		16,354		17,808		-8.2	%		117,941		121,380		-2.8	%
Wholesale revenue		2,408		1,406		71.3	%		19,976		9,567		108.8	%
Miscellaneous		524		531		-1.3	%		1,794		1,739		3.2	%
Total revenues	$	19,286	$	19,745		-2.3	%	$	139,711	$	132,686		5.3	%

Retail sales in thousands of Dths		1,272		1,183		7.5	%		10,108		9,549		5.9	%

Average retail revenue per Dth	$	12.86	$	15.05		-14.6	%	$	11.67	$	12.71		-8.2	%

SPPC’s retail gas revenues decreased for the three and nine months ended September 30, 2010, compared to the same periods in 2009 primarily due to decreased retail rates. Retail rates decreased as a result of SPPC’s 2009 Natural Gas and Propane Deferred Rate Case and BTER quarterly updates. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K. These decreases were partially offset by increased customer usage resulting from cooler weather in the second and third quarters of 2010. The average number of retail customers for the three and nine months ended September 30, 2010 increased by 1.1% and 0.8% respectively.

Wholesale revenues for the three and nine months ended September 30, 2010, increased compared to the same periods in 2009, primarily due to excess availability of gas.

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
●		Generation efficiency and
●		Volatility of commodity prices

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2010		2009		Prior Year %			2010		2009		Prior Year %

Energy Costs:
Fuel for Generation	$	66,133	$	89,125		-25.8	%	$	181,232	$	229,119		-20.9	%
Purchased Power	$	33,544	$	25,580		31.1	%	$	110,262	$	92,439		19.3	%
Total Energy Costs	$	99,677	$	114,705		-13.1	%	$	291,494	$	321,558		-9.3	%

MWhs
Fuel for Generation (in thousands)		1,525		1,696		-10.1	%		3,825		4,219		-9.3	%
Purchased Power (in thousands)		767		656		16.9	%		2,643		2,371		11.5	%
Total MWhs		2,292		2,352		-2.6	%		6,468		6,590		-1.9	%

Average cost per MWh
Average fuel cost per MWh of Generated Power	$	43.37	$	52.55		-17.5	%	$	47.38	$	54.31		-12.8	%
Average cost per MWh of Purchased Power	$	43.73	$	38.99		12.2	%	$	41.72	$	38.99		7.0	%
Total average cost per MWh	$	43.49	$	48.77		-10.8	%	$	45.07	$	48.79		-7.6	%

Energy costs and the average cost per MWh decreased for the three and nine months ended September 30, 2010, compared to the same period in 2009, primarily due to a decrease in hedging costs, partially offset by increased natural gas costs. Total system demand for the three and nine months ended September 30, 2010 decreased slightly.

●	The average cost per MWh for fuel for generation decreased for the three and nine months ending September 30, 2010, compared to the same period in 2009, primarily due to lower costs from hedging instruments partially offset by an increase in natural gas costs. Fuel for generation volume decreased due to outages at SPPC’s generating stations.

●	Purchase power costs, as a component of energy costs, and the average cost per MWh of purchased power increased primarily due to an increase in open market prices, which is a reflection of the increase in natural gas prices. Purchased power volume increased due to the outages discussed above.

Gas Purchased for Resale

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2010		2009		Prior Year %			2010		2009		Prior Year %


Gas purchased for resale	$	10,823	$	11,269		-4.0	%	$	101,536	$	101,457		0.1	%

Gas purchased for resale
(in thousands of Dths)		1,867		1,670		11.8	%		14,759		12,141		21.6	%

Average cost per Dth	$	5.80	$	6.75		-14.1	%	$	6.88	$	8.36		-17.7	%

Gas purchased for resale decreased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to decreased hedging costs partially offset by higher natural gas costs and increased volume. Gas purchased for resale increased slightly for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to higher natural gas costs and increased volume partially offset by decreased hedging costs. The volume of gas purchased for resale increased for the three and nine months ended September 30, 2010, compared to the same periods in 2009, primarily due to excess availability of gas. The average cost per Dth decreased for the three and nine months ended September 30, 2010, compared to the same periods in 2009, primarily due to decreased hedging costs.

Deferred Energy

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %

Deferred energy - electric	$	9,964	$	26,646		-62.6	%	$	17,189	$	68,222		-74.8	%
Deferred energy - gas		1,795		2,286		-21.5	%		7,646		1,923		297.6	%
	$	11,759	$	28,932				$	24,835	$	70,145

Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Deferred energy – electric for the three months ended September 30, 2010 and 2009 reflect amortization of deferred energy costs of ($6.1) million and ($0.4) million, respectively; and an over-collection of amounts recoverable in rates of $16.1 million and $27.0 million, respectively. For the nine months ended September 30, 2010 and 2009, amortization of deferred energy was ($17.3) million and ($1.6) million, respectively; with an over-collection of amounts recoverable in rates of $34.5 million and $69.8 million, respectively.

Deferred energy – gas for the three months ended September 30, 2010 and 2009 reflect amortization of deferred energy of ($0.7) million, and $0.0 million, respectively; and an over-collection of amounts recoverable in rates of $2.5 million and $2.3 million, respectively. For the nine months ended September 30, 2010 and 2009, amortization of deferred energy was ($5.9) million and $0.0 million, respectively; with an over-collection of amounts recoverable in rates of $13.5 million and $1.9 million, respectively.

Other Operating Expenses

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %

Other operating expense	$	39,490	$	38,843		1.7	%	$	118,450	$	123,748		-4.3	%
Maintenance expense	$	7, 419	$	8,173		-9.2	%	$	26,770	$	23,939		11.8	%
Depreciation and amortization	$	26,848	$	27,545		-2.5	%	$	79,737	$	80,043		-0.4	%

Other operating expense increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to external consulting fees. Also contributing to the increase was amortization of REPR costs; however, as discussed under Gross Margin, REPR costs do not have an effect on net income, partially offset by lower employee pension and benefit expenses.

Other operating expense decreased for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses and a reduction in the amortization of renewable energy program costs; partially offset by increased external consulting fees.

Maintenance expense decreased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to lower transmission maintenance costs.

Maintenance expense increased for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to a scheduled major outage at the Valmy Generating Station and combustion turbine maintenance at the Tracy Generating Station.

Depreciation and amortization decreased for the three and nine months ended September 30, 2010, compared to the same periods in 2009, primarily due to a decrease in amortizations partially offset by system growth in plant-in-service.

Interest Expense

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		Change from Prior Year %			2010		2009		Change from Prior Year %

Interest expense (net of AFUDC-debt: $698, $864, $1,586, $2,364)	$	16,983	$	16,787		1.2	%	$	51,141	$	51,473		-0.6	%

Interest expense increased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to the issuance of $150 million of 6.0% Series M General and Refunding Mortgage Notes in August 2009, partially offset by interest savings related to the partial redemption of $73.3 million of the $325 million Series P General and Refunding Mortgage Bonds in December 2009, and lower interest on credit facility balances. See Note 4, Long-Term Debt, of the Notes to Financial Statements of the 2009 Form 10-K for additional information regarding long-term debt.

Interest expense decreased slightly for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to those items noted above for the three months ended September 30 and the amortization of premiums associated with the issuance of $150 million of 6.0% Series M General and Refunding Mortgage Notes in August 2009, partially offset by the issuance of $150 million of 6.0% Series M General and Refunding Mortgage Notes in August 2009. See Note 4, Long-Term Debt, of the Notes to Financial Statements in the 2009 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)

	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			Change from Prior Year %			2010			2009			Change from Prior Year %

Interest Income (expense) on regulatory items	$	(2,528	)	$	(2,047	)		23.5	%	$	(6,788	)	$	(3,764	)		80.3	%
AFUDC-equity	$	1,029		$	942			9.3	%	$	2,360		$	2,535			-6.9	%
Other income	$	2,379		$	3,792			-37.3	%	$	14,276		$	12,299			16.1	%
Other expense	$	(1,285	)	$	(813	)		58.1	%	$	(7,555	)	$	(4,601	)		64.2	%

Interest expense on regulatory items increased for the three and nine months ended September 30, 2010, compared to the same period in 2009, due to higher over-collected deferred energy balances in 2010.

AFUDC-equity increased slightly for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to an increase in distribution construction. AFUDC-equity decreased slightly for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to a decrease in construction.

Other income decreased for the three months ended September 30, 2010, compared to the same period in 2009, primarily due to interest received for tax refunds in 2009. Other income increased for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to the gain on sale for the Independence Lake property in 2010, and further discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements, partially offset by a gain recognized in 2009 on the sale of the Farad hydro units and interest received for tax refunds in 2009.

Other expense increased for the three and nine months ended September 30, 2010, compared to the same period in 2009, due to an increase in donations related to Independence Lake.

ANALYSIS OF CASH FLOWS

Cash flows increased during the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to a reduction in cash used by investing and financing activities, partially offset by a decrease in cash from operating activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to reductions in BTER rates charged to customers and a slight increase in spending on energy conservation programs. These decreases were partially offset by a decrease in funding for pension plans compared to the same period in 2009.

Cash Used By Investing Activities. Cash used by investing activities decreased due to the slowdown in construction for infrastructure and proceeds from the sale of property.

Cash Used By Financing Activities. The decrease in cash used by financing activities is primarily due to a reduction in draws on SPPC’s revolving credit facility and a decrease in capital contributions from NVE, partially offset by a decrease in dividend payments to NVE.

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 outcome and economic conditions.

Available Liquidity as of September 30, 2010 (in millions)
	SPPC
Cash and Cash Equivalents	$	93.0
Balance available on Revolving Credit Facility (1)		234.1
- Less Reduction for Hedging Obligations (2)		(22.5	)
	$	304.6

(1)	As of October 27, 2010, SPPC had approximately $215.3 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.
(2)	Reduction for hedging obligations reflects balance as of August 31, 2010.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills and bank deposits. In addition to cash on hand, SPPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

SPPC has no significant debt maturities in 2010 or 2011. As of October 27, 2010, SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facilities. Furthermore, in order to fund long-term capital requirements, including maturing debt, SPPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facilities, the issuance of long-term debt, and capital contributions from NVE. 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, the amount of liquidity available to SPPC could be signif icantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, re-finance debt or obtain funding through an equity issuance by NVE.

During the nine months ended September 30, 2010, SPPC paid dividends to NVE of $48 million.

SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

SPPC’s contractual obligations changed from that reported in the 2009 Form 10-K for the following significant items: (i) the TUA with GBT with respect to the ON Line project; (ii) SPPC’s new revolving credit facility entered into in April 2010; and (iii) a long-term service agreement for its Tracy Generating Station, as detailed in Note 11, Commitments and Contingencies of the Condensed Notes to Financial Statements.

Financing Transactions

$250 Million Revolving Credit Facility

In April 2010, SPPC terminated its $332 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $250 million secured revolving credit facility, maturing in April 2013. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have increased from the prior facility reflecting current market conditions. The Administrative Agent for the facility is Bank of America, N.A. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the availability under the revolving credit facility to SPPC shall not be less than 50% of the total commitments there under.

The SPPC Credit Agreement contains one financial maintenance covenant that 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. In the event that SPPC did not meet the financial maintenance covenant or there is an event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC’s senior secured deb t rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

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 September 30, 2010, 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 of up to $600 million. However, depending on NVE’s or NPC’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 SPPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of September 30, 2010, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority (1) to issue additional long term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million,

b.	Financial covenants within SPPC’s financing agreements – As stated in Financing Transactions above, SPPC’s revolving credit facility agreement, dated November 2005, has been replaced with a new $250 million revolving credit agreement. Under the $250 million revolving credit facility, SPPC must 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. Based on September 30, 2010 financial statements, SPPC was in compliance with this covenant and could incur up to $858 million of additional indebtedness.

	All other financial covenants contained in SPPC’s revolving credit facility and its 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 under these additional covenants; and

c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.8 billion.

Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of September 30, 2010, $1.6 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $746.7 million of additional General and Refunding Mortgage Securities as of September 30, 2010. 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 Indenture.

Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under its credit facility, the potential exposure of SPPC to collateral calls under various contracts and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt. SPPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. In May 2010, Fitch upgraded the rating for SPPC’s senior secured debt to BBB from BBB- and revised the rating outlook from positive to stable. As of September 30, 2010, the ratings are as follows:

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

* Investment grade

S&P’s, Moody’s and Fitch’s rating outlooks for SPPC are Stable.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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 fol lowing 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, 2010 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 Condensed 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. 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.

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. As discussed under SPPC’s Financing Transactions, the availability under SPPC’s revolving credit facility is reduced by the amount of negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. The calculation of SPPC’s negative mark-to-market exposure as of August 31, 2010 was approximately $22.5 million, which amount was in effect for borrowings during the month of September 2010. Currently, SPPC only has hedging contracts with counterparties who are also lenders on the revolving credit facility; however, future contracts entered into with non-lenders may require SPPC to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, SPPC has suspended its hedging program as such expect its exposure to negative mark-to-market positions to decline.

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 NPC 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.

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 CPUC. In addition, the PUCN, CPUC, or the FERC have the authority to review allocations of costs of non-power goods and administrative services among 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/o r 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 and gas 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, 2010, NPC’s and SPPC’s balance sheets included credits of approximately $36.9 million and $152.0 million, respectively, of deferred energy costs of which credits of $102.4 million and $117.7 million are requested in the 2010 DEAA filings

made by the Utilities. 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 2009 and 2010, 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 2009 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.

ITEM 3A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2010, 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, 2010
	Expected Maturity Date
																					Fair
	2010		2011			2012			2013			2014			Thereafter			Total			Value
Long-Term Debt
NVE
Fixed Rate	$	-	$	-		$	63,670		$	-		$	230,039		$	191,500		$	485,209		$	498,070
Average Interest Rate		-		-			7.80	%		-			8.63	%		6.75	%		7.78	%

NPC
Fixed Rate	$	-	$	364,000		$	130,000		$	-		$	125,000		$	2,967,050		$	3,586,050		$	4,120,568
Average Interest Rate		-		8.14	%		6.50	%		-			7.38	%		6.41	%		6.62	%
Variable Rate	$	-	$	-		$	-		$	100,000		$	-		$	173,775		$	273,775		$	273,775
Average Interest Rate		-		-			-			2.51	%		-			0.80	%		1.43	%

SPPC
Fixed Rate	$	-	$	-		$	100,000		$	250,000		$	-		$	701,742		$	1,051,742		$	1,194,041
Average Interest Rate		-		-			6.25	%		5.45	%		-			6.27	%		6.07	%
Variable Rate	$	-	$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	214,675
Average Interest Rate		-		-			-			-			-			0.76	%		0.76	%

Total Debt	$	-	$	364,000		$	293,670		$	350,000		$	355,039		$	4,248,742		$	5,611,451		$	6,301,129

Commodity Price Risk

See the 2009 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, 2009.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $51.3 million as of September 30, 2010, which compares to balances of $73.2 million at December 31, 2009. The decrease from December 31, 2009 is primarily due to the decrease in prices of natural gas and power during the first two quarters of 2010.

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, 2010, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the second quarter of 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

NPC and SPPC

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 FERC’s July decision and remanded the case back to the FERC for application of factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation, 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 the 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 including the Nevada BCP, have settled and resolved all claims against BP Energy (“BP Settlement”). On August 25, 2009, the BP Settlement received final approval by the FERC, under 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 November 19, 2009, the Utilities, together with other interested parties, executed a settlement agreement with American Electric Power S ervice Corporation (“AEP Settlement”). On December 23, 2009, the AEP Settlement received final approval by the FERC, under which AEP was ordered to settle with the Utilities for an immaterial amount in return for a release of all claims by the Utilities and BCP against AEP. This amount was received in February 2010 from AEP in fulfillment of its obligations under the settlement agreement. The Utilities had previously 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 reached an agreement in principle under FERC settlement procedures 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 8, Commitments and Contingencies, of 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 2009 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 the 2009 Form 10-K, and quarterly reports for NVE, NPC and SPPC on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6.EXHIBITS

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

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

10.1

Transmission Use and Capacity Agreement between Nevada Power Company, Sierra Pacific Power Company and Great Basin Transmission, LLC dated August 20, 2010.

Nevada Power Company:

10.2

Revolving Credit Facility dated April 28, 2010 between Nevada Power Company and Wells Fargo, N.A., as administrative agent for the lenders.

Sierra Pacific Power Company:

10.3

Collective Bargaining Agreement dated as of August 16, 2010, effective through August 15, 2013, between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local Union No. 1245.

10.4

Revolving Credit Facility dated April 28, 2010 between Sierra Pacific Power Company and Bank of America, N.A., as administrative agent for the lenders.

(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.

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, 2010	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)

Date: October 29, 2010	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, 2010	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)

Date: October 29, 2010	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, 2010	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)

Date: October 29, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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