Sierra Pacific Power 10-Q 2011 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED   September 30, 2011

OR

¨ 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 the definitions 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 Exchange 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 November 1, 2011
Common Stock, $1.00 par value of NV Energy, Inc.	235,999,750 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 Company.

1

NV ENERGY, INC. NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY QUARTERLY REPORTS ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2011 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, 2011 and 2010	5
			Consolidated Balance Sheet – September 30, 2011 and December 31, 2010	6
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010	8
			Consolidated Statements of Shareholders’ Equity - Nine Months Ended September 30, 2011 and 2010	9
		Nevada Power Company
			Consolidated Income Statements  – Three and Nine Months Ended September 30, 2011 and 2010	10
			Consolidated Balance Sheet – September 30, 2011 and December 31, 2010	11
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011  and 2010	13
			Consolidated Statements of Shareholder’s Equity - Nine Months Ended September 30, 2011 and 2010	14
		Sierra Pacific Power Company
			Consolidated Income Statements – Three and Nine Months Ended September 30, 2011 and 2010	15
			Consolidated Balance Sheet – September 30, 2011 and December 31, 2010	16
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010	18
			Consolidated Statements of Shareholder’s Equity - Nine Months Ended September 30, 2011 and 2010	19
		Condensed Notes to Financial Statements
			Note 1.     Summary of Significant Accounting Policies	20
			Note 2.     Segment Information	21
			Note 3.     Regulatory Actions	23
			Note 4.     Long-Term Debt	27
			Note 5.     Fair Value of Financial Instruments	28
			Note 6.     Derivatives and Hedging Activities	28
			Note 7.     Retirement Plan and Post-Retirement Benefits	30
			Note 8.     Commitments and Contingencies	32
			Note 9.     Earnings per Share (NVE)	35
			Note 10.  Assets Held for Sale	35
			Note 11.  Dividends	36
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
		NV Energy, Inc.		43
		Nevada Power Company		48
		Sierra Pacific Power Company		56
	ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		66
	ITEM 4.	Controls and Procedures		66
	PART II – OTHER INFORMATION
	ITEM 1.	Legal Proceedings		67
	ITEM 1A.	Risk Factors		67
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		67
	ITEM 3.	Defaults Upon Senior Securities		67
	ITEM 5.	Other Information		67
	ITEM 6.	Exhibits		68
	Signature Page and Certifications			70

2

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)
Acronym/Term	Meaning
2010 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2010
AFUDC-debt	Allowance for Borrowed Funds Used During Construction
AFUDC-equity	Allowance for Equity Funds Used During Construction
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CAISO	California Independent System Operator Corporation
CalPeco	California Pacific Electric Company
CALPX	California Power Exchange
CWIP	Construction Work-in-Progress
d/b/a	Doing business as
DEAA	Deferred Energy Accounting Adjustment
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
EWAM	Enterprise Work Asset Management System
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd.
Fort Churchill	226 megawatt nominally rated Fort Churchill Generating Station
GAAP	Generally Accepted Accounting Principles in the United States
GBT	Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC
GBT-South	Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT
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
Independence Lake	2,325 acres of forestland in the Sierra Nevada Mountains purchased from NV Energy, Inc. by The Nature Conservancy
IRP	Integrated Resource Plan
kV	Kilovolt
kWh	Kilowatt hour
Legislature	Nevada State Legislature
Lenzie Generating Station	1,102 megawatt nominally rated Chuck Lenzie Generating Station
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 Electric Investment Company
NERC	North American Electric Reliability Corporation
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	A smart grid infrastructure that is expected to enable the widespread use of smart meters that will provide
	customers the ability to more directly manage their energy usage
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC	Portfolio Energy Credit
Portfolio Standard	Nevada 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

3

SNWA	Southern Nevada Water Authority
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
Term Loan	$195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank, N.A.,
	as administrative agent for the lenders a party thereto
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 with GBT-South
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

4

NV ENERGY, INC.
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	1,017,796		$	1,128,039		$	2,333,710		$	2,625,211
OPERATING EXPENSES:
Fuel for power generation		216,779			247,233			519,920			650,514
Purchased power		223,348			249,854			518,672			522,538
Gas purchased for resale		10,137			10,823			87,753			101,536
Deferred energy		(33,620	)		34,055			(43,678	)		106,554
Other operating expenses		127,645			112,741			331,166			320,755
Maintenance		11,369			31,126			73,317			85,715
Depreciation and amortization		93,737			83,423			266,445			249,067
Taxes other than income		15,205			15,420			46,134			47,532
Total Operating Expenses		664,600			784,675			1,799,729			2,084,211
OPERATING INCOME		353,196			343,364			533,981			541,000
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $1,326, $6,485,
$10,371 and $17,349)		(80,496	)		(80,789	)		(238,718	)		(241,625	)
Interest expense on regulatory items		(4,316	)		(3,685	)		(12,140	)		(8,753	)
AFUDC-equity		1,690			7,824			12,854			20,915
Other income		4,645			9,246			14,942			30,524
Other expense		(9,857	)		(4,313	)		(23,600	)		(17,038	)
Total Other Income (Expense)		(88,334	)		(71,717	)		(246,662	)		(215,977	)
Income Before Income Tax Expense		264,862			271,647			287,319			325,023
Income tax expense		91,400			94,101			98,639			112,252
NET INCOME	$	173,462		$	177,546		$	188,680		$	212,771
Amount per share basic and diluted - (Note 9)
Net income per share - basic	$	0.74		$	0.76		$	0.80		$	0.91
Net income per share - diluted	$	0.73		$	0.75		$	0.80		$	0.90
Weighted Average Shares of Common Stock Outstanding - basic		235,990,373			235,117,058			235,796,321			234,991,208
Weighted Average Shares of Common Stock Outstanding - diluted		237,901,330			236,477,187			237,320,796			236,136,725
Dividends Declared Per Share of Common Stock	$	0.12		$	0.11		$	0.36		$	0.33
The accompanying notes are an integral part of the financial statements.

5

  

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
		September 30,		December 31,
		2011		2010
ASSETS
Current Assets:
Cash and cash equivalents		$	137,475	$	86,189
Accounts receivable less allowance for uncollectible accounts:
	2011 - $31,297; 2010 - $28,684		487,384		354,010
Materials, supplies and fuel, at average cost			141,107		114,520
Risk management assets (Note 6)			64		4,007
Current income taxes receivable			82		82
Deferred income taxes			114,414		130,800
Other current assets			47,572		42,330
Total Current Assets			928,098		731,938
Utility Property:
Plant in service			11,944,740		11,068,518
Construction work-in-progress			413,299		908,579
Total			12,358,039		11,977,097
Less accumulated provision for depreciation			3,167,925		3,047,438
Total Utility Property, Net			9,190,114		8,929,659
Investments and other property, net			54,968		61,613
Deferred Charges and Other Assets:
Deferred energy (Note 3)			105,778		117,623
Regulatory assets			1,083,898		1,237,159
Regulatory asset for pension plans			255,037		269,472
Other deferred charges and assets			148,872		166,882
Total Deferred Charges and Other Assets			1,593,585		1,791,136
Assets Held for Sale (Note 10)			-		155,322
TOTAL ASSETS		$	11,766,765	$	11,669,668
	(Continued)

6

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
	September 30,			December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY	2011			2010
Current Liabilities:
Current maturities of long-term debt (Note 4)	$	136,139		$	355,929
Accounts payable		341,500			346,409
Accrued expenses		106,260			133,851
Risk management liabilities (Note 6)		1,515			33,229
Deferred energy (Note 3)		283,046			315,839
Other current liabilities		60,357			70,638
Total Current Liabilities		928,817			1,255,895
Long-term debt (Note 4)		5,038,232			4,924,109
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		1,317,176			1,246,410
Deferred investment tax credit		16,796			19,204
Accrued retirement benefits		149,008			148,841
Risk management liabilities (Note 6)		416			-
Regulatory liabilities		476,305			428,114
Other deferred credits and liabilities		374,326			265,571
Total Deferred Credits and Other Liabilities		2,334,027			2,108,140
Liabilities Held for Sale (Note 10)		-			30,706
Shareholders' Equity:
Common stock, $1.00 par value; 350 million shares authorized;
235,999,749 and 235,322,553 issued and outstanding for 2011and 2010		236,000			235,323
Other paid-in capital		2,713,958			2,705,954
Retained earnings		520,205			416,432
Accumulated other comprehensive loss		(4,474	)		(6,891	)
Total Shareholders' Equity		3,465,689			3,350,818
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	11,766,765		$	11,669,668
The accompanying notes are an integral part of the financial statements.
(Concluded)

7

 

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	For the Nine Months Ended
	September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	188,680		$	212,771
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		266,445			249,067
Deferred taxes and deferred investment tax credit		99,920			126,659
AFUDC-equity		(12,854	)		(20,915	)
Deferred energy		(20,802	)		134,969
Gain on sale of asset		-			(7,575	)
Amortization of other regulatory assets		124,213			59,643
Deferred rate increase		65,306			(6,250	)
Other, net		25,633			8,922
Changes in certain assets and liabilities:
Accounts receivable		(132,078	)		(82,833	)
Materials, supplies and fuel		(26,290	)		5,883
Other current assets		(5,242	)		475
Accounts payable		32,397			43,110
Accrued retirement benefits		167			(13,658	)
Other current liabilities		(37,869	)		(13,589	)
Risk management assets and liabilities		1,913			10,086
Other deferred assets		(14,982	)		(4,912	)
Other regulatory assets		(72,480	)		(41,679	)
Other deferred liabilities		(15,043	)		(4,850	)
Net Cash from Operating Activities		467,034			655,324
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(469,870	)		(520,175	)
Proceeds from sale of asset		166,603			18,225
Customer advances for construction		(7,159	)		(6,030	)
Contributions in aid of construction		79,343			46,217
Investments and other property - net		410			(9,090	)
Net Cash used by Investing Activities		(230,673	)		(470,853	)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		386,784			660,711
Retirement of long-term debt		(480,689	)		(453,656	)
Settlement of interest rate lock		(14,944	)		-
Sale of common stock		8,681			4,086
Dividends paid		(84,907	)		(77,561	)
Net Cash from (used by) Financing Activities		(185,075	)		133,580
Net Increase in Cash and Cash Equivalents		51,286			318,051
Beginning Balance in Cash and Cash Equivalents		86,189			62,706
Ending Balance in Cash and Cash Equivalents	$	137,475		$	380,757
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	251,011		$	264,974
Income taxes	$	1		$	14
Significant non-cash transactions:
Accrued construction expenses as of September 30,	$	158,849		$	65,163
Capital lease obligations incurred	$	-		$	15,336
The accompanying notes are an integral part of the financial statements.

8

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
										Accumulated
	Common		Common		Other					Other			Total
	Stock		Stock		Paid-in		Retained			Comprehensive			Shareholders'
	Shares		Amount		Capital		Earnings			Income (Loss)			Equity
December 31, 2009		234,834,169	$	234,834	$	2,700,329	$	295,248		$	(6,488	)	$	3,223,923
Net Income		-		-		-		212,771			-			212,771
Dividend reinvestment and employee benefits		338,455		339		3,748		-			-			4,087
Change in compensation retirement
benefits liability and amortization
(net of taxes ($51))		-		-		-		-			94			94
Dividends declared		-		-		-		(77,561	)		-			(77,561	)
September 30, 2010		235,172,624	$	235,173	$	2,704,077	$	430,458		$	(6,394	)	$	3,363,314
December 31, 2010		235,322,553	$	235,323	$	2,705,954	$	416,432		$	(6,891	)	$	3,350,818
Net Income		-		-		-		188,680			-			188,680
Dividend reinvestment and employee benefits		677,196		677		7,692		-			-			8,369
Tax benefit from stock options exercised		-		-		312		-			-			312
Change in compensation retirement
benefits liability and amortization
(net of taxes ($1,302))		-		-		-		-			2,417			2,417
Dividends declared		-		-		-		(84,907	)		-			(84,907	)
September 30, 2011		235,999,749	$	236,000	$	2,713,958	$	520,205		$	(4,474	)	$	3,465,689
The accompanying notes are an integral part of the financial statements.

9

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	798,914		$	870,950		$	1,662,880		$	1,836,144
OPERATING EXPENSES:
Fuel for power generation		162,976			181,100			378,790			469,282
Purchased power		181,733			216,309			399,707			412,276
Deferred energy		(10,354	)		22,296			(1,274	)		81,719
Other operating expenses		88,455			73,762			215,491			203,773
Maintenance		3,460			23,707			45,122			58,945
Depreciation and amortization		67,212			56,575			186,798			169,330
Taxes other than income		9,105			9,038			28,209			28,857
Total Operating Expenses		502,587			582,787			1,252,843			1,424,182
OPERATING INCOME		296,327			288,163			410,037			411,962
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $842,
$5,787, $8,962 and $15,763)		(55,267	)		(54,144	)		(163,036	)		(161,496	)
Interest expense on regulatory items		(2,478	)		(1,157	)		(5,911	)		(1,965	)
AFUDC-equity		1,026			6,795			10,979			18,555
Other income		2,990			3,842			9,298			9,084
Other expense		(7,324	)		(3,034	)		(15,235	)		(9,338	)
Total Other Income (Expense)		(61,053	)		(47,698	)		(163,905	)		(145,160	)
Income Before Income Tax Expense		235,274			240,465			246,132			266,802
Income tax expense		80,666			81,537			84,481			90,416
NET INCOME	$	154,608		$	158,928		$	161,651		$	176,386
The accompanying notes are an integral part of the financial statements.

10

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
		September 30,		December 31,
		2011		2010
ASSETS
Current Assets:
Cash and cash equivalents		$	34,753	$	60,077
Accounts receivable less allowance for uncollectible accounts:
	2011 - $28,716; 2010 - $26,428		370,567		224,704
Materials, supplies and fuel, at average cost			75,856		66,459
Risk management assets (Note 6)			64		3,476
Deferred income taxes			73,084		76,282
Other current assets			32,987		29,680
Total Current Assets			587,311		460,678
Utility Property:
Plant in service			8,394,645		7,552,097
Construction work-in-progress			286,694		825,079
	Total		8,681,339		8,377,176
Less accumulated provision for depreciation			1,902,992		1,828,366
	Total Utility Property, Net		6,778,347		6,548,810
Investments and other property, net			49,094		55,305
Deferred Charges and Other Assets:
Deferred energy (Note 3)			105,778		117,623
Regulatory assets			769,136		871,982
Regulatory asset for pension plans			125,453		133,410
Other deferred charges and assets			108,756		114,016
Total Deferred Charges and Other Assets			1,109,123		1,237,031
TOTAL ASSETS		$	8,523,875	$	8,301,824
(Continued)

11

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
	September 30,			December 31,
	2011			2010
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt (Note 4)	$	136,139		$	355,929
Accounts payable		220,601			232,279
Accounts payable, affiliated companies		29,056			29,334
Accrued expenses		65,459			89,638
Risk management liabilities (Note 6)		1,258			22,764
Deferred energy (Note 3)		174,155			171,349
Other current liabilities		46,263			54,607
Total Current Liabilities		672,931			955,900
Long-term debt (Note 4)		3,352,044			3,221,833
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		982,194			908,094
Deferred investment tax credit		6,425			7,255
Accrued retirement benefits		35,878			31,907
Risk management liabilities (Note 6)		416			-
Regulatory liabilities		267,417			225,983
Other deferred credits and liabilities		293,259			189,220
Total Deferred Credits and Other Liabilities		1,585,589			1,362,459
Shareholder's Equity:
Common stock, $1.00 par value, 1,000 shares authorized,
issued and outstanding for 2011 and 2010		1			1
Other paid-in capital		2,308,219			2,254,219
Retained earnings		607,939			511,288
Accumulated other comprehensive loss		(2,848	)		(3,876	)
Total Shareholder's Equity		2,913,311			2,761,632
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	8,523,875		$	8,301,824
The accompanying notes are an integral part of the financial statements.
(Concluded)

12

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	For the Nine Months Ended
	September 30,
	2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income		$	161,651		$	176,386
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			186,798			169,330
Deferred taxes and deferred investment tax credit			85,488			90,930
AFUDC-equity			(10,979	)		(18,555	)
Deferred energy			14,651			99,407
Amortization of other regulatory assets			62,994			41,415
Deferred rate increase			65,306			(6,250	)
Other, net			18,507			3,085
Changes in certain assets and liabilities:
Accounts receivable			(145,862	)		(108,609	)
Materials, supplies and fuel			(9,100	)		4,678
Other current assets			(3,307	)		233
Accounts payable			26,434			35,249
Accrued retirement benefits			3,971			(13,320	)
Other current liabilities			(32,523	)		(8,474	)
Risk management assets and liabilities			1,382			7,903
Other deferred assets			(13,788	)		(2,214	)
Other regulatory assets			(44,383	)		(28,175	)
Other deferred liabilities			(16,676	)		(3,233	)
Net Cash from Operating Activities			350,564			439,786
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)			(367,097	)		(421,793	)
Proceeds from sale of asset			31,997			3,254
Customer advances for construction			(2,165	)		(3,891	)
Contributions in aid of construction			64,617			42,034
Investments and other property - net			395			(99	)
Net Cash used by Investing Activities			(272,253	)		(380,495	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt			386,884			637,975
Retirement of long-term debt			(464,575	)		(412,201	)
Settlement of interest rate lock			(14,944	)		-
Additional investment by parent company			54,000			-
Dividends paid			(65,000	)		(62,000	)
Net Cash from Financing Activities			(103,635	)		163,774
Net Increase (Decrease) in Cash and Cash Equivalents			(25,324	)		223,065
Beginning Balance in Cash and Cash Equivalents			60,077			42,609
Ending Balance in Cash and Cash Equivalents		$	34,753		$	265,674
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest		$	182,992		$	180,732
Income taxes		$	1		$	2
Significant non-cash transactions:
Accrued construction expenses as of September 30,		$	141,384		$	57,638
Capital lease obligations incurred		$	-		$	15,336
The accompanying notes are an integral part of the financial statements.

13

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
													Accumulated
	Common		Common			Other							Other				Total
	Stock		Stock			Paid-in			Retained				Comprehensive				Shareholder's
	Shares		Amount			Capital			Earnings				Income (Loss)				Equity
December 31, 2009		1,000		$	1		$	2,254,189		$	399,345			$	(3,496	)		$	2,650,039
Net Income		-			-			-			176,386				-				176,386
Change in compensation retirement
benefits liability and amortization
(net of taxes ($27))		-			-			-			-				50				50
Dividends declared		-			-			-			(62,000	)			-				(62,000	)
September 30, 2010		1,000		$	1		$	2,254,189		$	513,731			$	(3,446	)		$	2,764,475
December 31, 2010		1,000		$	1		$	2,254,219		$	511,288			$	(3,876	)		$	2,761,632
Net Income		-			-			-			161,651				-				161,651
Capital contribution from parent		-			-			54,000			-				-				54,000
Change in compensation retirement
benefits liability and amortization
(net of taxes ($554))		-			-			-			-				1,028				1,028
Dividends declared		-			-			-			(65,000	)			-				(65,000	)
September 30, 2011		1,000		$	1		$	2,308,219		$	607,939			$	(2,848	)		$	2,913,311
The accompanying notes are an integral part of the financial statements.

14

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
OPERATING REVENUES:
Electric	$	202,263		$	237,798		$	545,462		$	649,337
Gas		16,615			19,286			125,357			139,711
Total Operating Revenues		218,878			257,084			670,819			789,048
OPERATING EXPENSES:
Fuel for power generation		53,803			66,133			141,130			181,232
Purchased power		41,615			33,545			118,965			110,262
Gas purchased for resale		10,137			10,823			87,753			101,536
Deferral of energy - electric - net		(22,095	)		9,964			(45,924	)		17,189
Deferral of energy - gas - net		(1,171	)		1,795			3,520			7,646
Other operating expenses		38,529			38,004			113,432			114,371
Maintenance		7,909			7,419			28,195			26,770
Depreciation and amortization		26,525			26,848			79,647			79,737
Taxes other than income		6,052			6,330			17,675			18,494
Total Operating Expenses		161,304			200,861			544,393			657,237
OPERATING INCOME		57,574			56,223			126,426			131,811
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $484,
$698, $1,409 and $1,586)		(16,861	)		(16,983	)		(50,581	)		(51,141	)
Interest expense on regulatory items		(1,838	)		(2,528	)		(6,229	)		(6,788	)
AFUDC-equity		664			1,029			1,875			2,360
Other income		1,448			2,379			4,677			14,276
Other expense		(2,255	)		(1,285	)		(7,403	)		(7,555	)
Total Other Income (Expense)		(18,842	)		(17,388	)		(57,661	)		(48,848	)
Income Before Income Tax Expense		38,732			38,835			68,765			82,963
Income tax expense		13,396			14,373			23,341			30,066
NET INCOME	$	25,336		$	24,462		$	45,424		$	52,897
The accompanying notes are an integral part of the financial statements.

15

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
		September 30,		December 31,
		2011		2010
ASSETS
Current Assets:
Cash and cash equivalents		$	66,311	$	9,552
Accounts receivable less allowance for uncollectible accounts:
	2011 - $2,581; 2010 - $2,256		116,685		129,306
Materials, supplies and fuel, at average cost			65,251		48,061
Risk management assets (Note 6)			-		531
Intercompany income taxes receivable			10,351		10,351
Deferred income taxes			40,343		53,282
Other current assets			12,597		11,633
Total Current Assets			311,538		262,716
Utility Property:
Plant in service			3,550,095		3,516,421
Construction work-in-progress			126,605		83,500
	Total		3,676,700		3,599,921
Less accumulated provision for depreciation			1,264,933		1,219,072
	Total Utility Property, Net		2,411,767		2,380,849
Investments and other property, net			5,522		5,956
Deferred Charges and Other Assets:
Regulatory assets			314,762		365,177
Regulatory asset for pension plans			126,619		131,734
Other deferred charges and assets			33,138		45,268
Total Deferred Charges and Other Assets			474,519		542,179
Assets Held for Sale (Note 10)			-		155,322
TOTAL ASSETS		$	3,203,346	$	3,347,022
(Continued)

16

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
	September 30,			December 31,
	2011			2010
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Accounts payable	$	86,146		$	90,206
Accounts payable, affiliated companies		28,786			10,812
Accrued expenses		29,276			33,788
Dividends Declared		-			54,000
Risk management liabilities (Note 6)		257			10,465
Deferred energy (Note 3)		108,891			144,490
Other current liabilities		14,095			16,029
Total Current Liabilities		267,451			359,790
Long-term debt (Note 4)		1,179,688			1,195,775
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		401,686			395,454
Deferred investment tax credit		10,371			11,949
Accrued retirement benefits		105,798			110,302
Regulatory liabilities		208,888			202,131
Other deferred credits and liabilities		68,078			67,495
Total Deferred Credits and Other Liabilities		794,821			787,331
Liabilities Held for Sale (Note 10)		-			30,706
Shareholder's Equity:
Common stock, $3.75 par value, 20,000,000 shares authorized,
1,000 shares issued and ouutstanding for 2011 and 2010		4			4
Other paid-in capital		1,111,574			1,111,262
Retained earnings		(149,802	)		(135,226	)
Accumulated other comprehensive loss		(390	)		(2,620	)
Total Shareholder's Equity		961,386			973,420
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	3,203,346		$	3,347,022
The accompanying notes are an integral part of the financial statements.
(Concluded)

17

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	For the Nine Months Ended
	September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	45,424		$	52,897
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		79,647			79,737
Deferred taxes and deferred investment tax credit		23,296			21,134
AFUDC-equity		(1,875	)		(2,360	)
Deferred energy		(35,453	)		35,562
Gain on sale of asset		-			(7,575	)
Amortization of other regulatory assets		59,855			18,056
Other, net		8,015			4,454
Changes in certain assets and liabilities:
Accounts receivable		13,917			51,221
Materials, supplies and fuel		(17,190	)		1,184
Other current assets		(964	)		1,423
Accounts payable		12,833			1,112
Accrued retirement benefits		(4,504	)		(1,939	)
Other current liabilities		(6,447	)		1,615
Risk management assets and liabilities		531			2,183
Other deferred assets		(1,194	)		(2,698	)
Other regulatory assets		(28,097	)		(13,504	)
Other deferred liabilities		(2,501	)		(2,691	)
Net Cash from Operating Activities		145,293			239,811
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(102,773	)		(111,476	)
Proceeds from sale of asset		134,606			14,971
Customer advances for construction		(4,994	)		(2,139	)
Contributions in aid of construction		14,726			4,183
Investments and other property - net		15			(119	)
Net Cash from (used by) Investing Activities		41,580			(94,580	)
CASH FLOWS USED BY FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		-			22,736
Retirement of long-term debt		(16,114	)		(41,308	)
Dividends paid		(114,000	)		(48,000	)
Net Cash used by Financing Activities		(130,114	)		(66,572	)
Net Increase (Decrease) in Cash and Cash Equivalents		56,759			78,659
Beginning Balance in Cash and Cash Equivalents		9,552			14,359
Ending Balance in Cash and Cash Equivalents	$	66,311		$	93,018
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	45,632		$	48,990
Income taxes	$	-		$	12
Significant non-cash transactions:
Accrued construction expenses as of September 30,	$	17,465		$	7,525
The accompanying notes are an integral part of the financial statements.

18

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
										Accumulated
										Other			Total
	Common		Common		Other Paid-		Retained			Comprehensive			Shareholder's
	Stock Shares		Stock Amount		in Capital		Deficit			Income (Loss)			Equity
December 31, 2009		1,000	$	4	$	1,111,260	$	(99,601	)	$	(2,405	)	$	1,009,258
Net Income		-		-		-		52,897			-			52,897
Change in compensation retirement
benefits liability and amortization
(net of taxes ($14))		-		-		-		-			26			26
Dividends declared		-		-		-		(48,000	)		-			(48,000	)
September 30, 2010		1,000	$	4	$	1,111,260	$	(94,704	)	$	(2,379	)	$	1,014,181
December 31, 2010		1,000	$	4	$	1,111,262	$	(135,226	)	$	(2,620	)	$	973,420
Net Income		-		-		-		45,424			-			45,424
Tax benefit from stock options exercised		-		-		312		-			-			312
Change in compensation retirement
benefits liability and amortization
(net of taxes ($1,201))		-		-		-		-			2,230			2,230
Dividends declared		-		-		-		(60,000	)		-			(60,000	)
September 30, 2011		1,000	$	4	$	1,111,574	$	(149,802	)	$	(390	)	$	961,386
The accompanying notes are an integral part of the financial statements.

19

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., 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 2010 Form 10-K.

During the third quarter 2010, NPC terminated a long term service agreement for one of its generating stations.  The estimated termination payment was not material to the third quarter but would have been material to the fourth quarter of 2010. Therefore, management determined it more appropriate to revise third quarter 2010 for the estimated termination payment.  As disclosed in our 2010 Form 10-K, Note 18, Quarterly Financial Data, of the Notes to Financial Statements, operating income, net income and earnings per share were reduced by $8.0 million, $5.2 million (net of taxes) and $0.02 per share (net of taxes), share respectively.

The results of operations and cash flows of NVE, NPC and SPPC for the nine months ended September 30, 2011, are not necessarily indicative of the results to be expected for the full year.

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, 2011, 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.

Recent Accounting Standards Updates

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

20

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 are effective for NVE and the Utilities as of January 1, 2011.  The adoption of this guidance did not have, nor is it expected to have, a significant impact on the disclosure requirements for NVE and the Utilities.

Other Comprehensive Income

In June 2011, the FASB amended the Comprehensive Income Topic as reflected in the FASB Accounting Standards Codification for presentation of comprehensive income.  NVE and the Utilities will be required to adopt this amendment for our fiscal year ending after December 15, 2011.  The amendment does not change the amount of comprehensive income reported, but rather establishes a standard for the reporting and presentation of comprehensive income providing an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  NVE and the Utilities are evaluating our presentation options, but do not expect the amendment to have a significant impact on our reporting or presentation requirements.

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 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
September 30, 2011	NVE
	Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues (1)	$	1,017,796		$	4		$	798,914		$	218,878		$	202,263		$	16,615
Energy Costs:
Fuel for power generation		216,779			-			162,976			53,803			53,803			-
Purchased power		223,348			-			181,733			41,615			41,615			-
Gas purchased for resale		10,137			-			-			10,137			-			10,137
Deferred energy		(33,620	)		-			(10,354	)		(23,266	)		(22,095	)		(1,171	)
Total Energy Costs	$	416,644		$	-		$	334,355		$	82,289		$	73,323		$	8,966
Gross Margin	$	601,152		$	4		$	464,559		$	136,589		$	128,940		$	7,649
Other operating expenses (1)		127,645			661			88,455			38,529
Maintenance		11,369			-			3,460			7,909
Depreciation and amortization		93,737			-			67,212			26,525
Taxes other than income		15,205			48			9,105			6,052
Operating Income (Loss)	$	353,196		$	(705	)	$	296,327		$	57,574

21

Nine Months Ended
September 30, 2011	NVE
	Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues(1)	$	2,333,710		$	11		$	1,662,880		$	670,819		$	545,462		$	125,357
Energy Costs:
Fuel for power generation		519,920			-			378,790			141,130			141,130			-
Purchased power		518,672			-			399,707			118,965			118,965			-
Gas purchased for resale		87,753			-			-			87,753			-			87,753
Deferred energy		(43,678	)		-			(1,274	)		(42,404	)		(45,924	)		3,520
Total Energy Costs	$	1,082,667		$	-		$	777,223		$	305,444		$	214,171		$	91,273
Gross Margin	$	1,251,043		$	11		$	885,657		$	365,375		$	331,291		$	34,084
Other operating expenses (1)		331,166			2,243			215,491			113,432
Maintenance		73,317			-			45,122			28,195
Depreciation and amortization		266,445			-			186,798			79,647
Taxes other than income		46,134			250			28,209			17,675
Operating Income (Loss)	$	533,981		$	(2,482	)	$	410,037		$	126,426

Three Months Ended
September 30, 2010	NVE
	Consolidated		NVE Other			NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues(2)	$	1,128,039	$	5		$	870,950	$	257,084	$	237,798	$	19,286
Energy Costs:
Fuel for power generation		247,233		-			181,100		66,133		66,133		-
Purchased power		249,854		-			216,309		33,545		33,545		-
Gas purchased for resale		10,823		-			-		10,823		-		10,823
Deferred energy		34,055		-			22,296		11,759		9,964		1,795
Total Energy Costs	$	541,965	$	-		$	419,705	$	122,260	$	109,642	$	12,618
Gross Margin(2)	$	586,074	$	5		$	451,245	$	134,824	$	128,156	$	6,668
Other operating expenses		112,741		975			73,762		38,004
Maintenance		31,126		-			23,707		7,419
Depreciation and amortization		83,423		-			56,575		26,848
Taxes other than income		15,420		52			9,038		6,330
Operating Income (Loss)(3)	$	343,364	$	(1,022	)	$	288,163	$	56,223

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Nine Months Ended
September 30, 2010	NVE
	Consolidated		NVE Other			NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues (2)	$	2,625,211	$	19		$	1,836,144	$	789,048	$	649,337	$	139,711
Energy Costs:
Fuel for power generation		650,514		-			469,282		181,232		181,232		-
Purchased power		522,538		-			412,276		110,262		110,262		-
Gas purchased for resale		101,536		-			-		101,536		-		101,536
Deferred energy		106,554		-			81,719		24,835		17,189		7,646
Total Energy Costs	$	1,381,142	$	-		$	963,277	$	417,865	$	308,683	$	109,182
Gross Margin(2)	$	1,244,069	$	19		$	872,867	$	371,183	$	340,654	$	30,529
Other operating expenses		320,755		2,611			203,773		114,371
Maintenance		85,715		-			58,945		26,770
Depreciation and amortization		249,067		-			169,330		79,737
Taxes other than income		47,532		181			28,857		18,494
Operating Income (Loss)(3)	$	541,000	$	(2,773	)	$	411,962	$	131,811

(1)	Effective July 1, 2011, included in operating revenues were EEPR revenues, for which costs related to the program are included in other operating expense and therefore have no effect on operating income.   See Note 3, Regulatory Actions.
(2)	As reported in our 2010 Form 10-K, amounts for REPR are presented net.  As such, revenues and gross margin for the three months ended September 30, 2010 were reduced by $3.5 million, $2.0 million and $1.5 million for NVE, NPC and SPPC, respectively, from that reported in the Forms 10-Q for the period ended September 30, 2010.  Revenues and gross margin for the nine months ended September 30, 2010 were reduced by $8.7 million, $4.6 million and $4.1 million for NVE, NPC and SPPC, respectively, from that reported in the Forms 10-Q for the period ended September 30, 2010.
(3)	During the third quarter 2010, NPC terminated a long-term service agreement from one of its generating stations.  The estimated termination payment was not considered material to the third quarter but would have been material to the fourth quarter; therefore, as disclosed in our 2010 Form 10-K, third quarter 2010 was revised to reflect the estimated termination payment.  As such, operating  income for the three and nine months ended September 30, 2010 was reduced by $8.0 million, before tax,  for  NVE and NPC, from that reported in the Forms 10-Q for the quarterly period ended September 30, 2010.  See Note 1, Summary of Significant Accounting Policies.

NOTE 3.                      REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 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, 2011 (dollars in thousands):

	September 30, 2011
	NVE Total			NPC Electric				SPPC Electric			SPPC Gas
Nevada Deferred Energy
Cumulative Balance requested in 2011 DEAA	$	(334,102	)	$	(189,032	)	(1)	$	(115,955	)	$	(29,115	)
2011 Amortization		166,081			78,624				75,464			11,993
2011 Deferred Energy Over Collections (2)		(129,925	)		(78,647	)			(34,646	)		(16,632	)
Nevada Deferred Energy Balance at September 30, 2011 - Subtotal	$	(297,946	)	$	(189,055	)		$	(75,137	)	$	(33,754	)
Reinstatement of deferred energy (effective 6/07, 10 years)		120,678			120,678				-			-
Total Deferred Energy	$	(177,268	)	$	(68,377	)		$	(75,137	)	$	(33,754	)
Deferred Assets
Deferred energy	$	105,778		$	105,778			$	-		$	-
Current Liabilities
Deferred energy		(283,046	)		(174,155	)			(75,137	)		(33,754	)
Total Deferred Energy	$	(177,268	)	$	(68,377	)		$	(75,137	)	$	(33,754	)

(1)	Refer to NPC 2010 DEAA “Settled Regulatory Actions” in Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 Form 10-K for separate discussion regarding rate offset of this balance.
(2)	These deferred energy over collections will be filed in the March 2012 DEAA filings.

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Nevada Power Company and Sierra Pacific Power Company

          Assembly Bill 215

In 2011, the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  The Utilities will still be required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate.  SPPC filed an application to change its quarterly DEAA rates for both electric and gas in July 2011, and in October 2011, the PUCN accepted a stipulation authorizing the first quarterly adjustment to the electric DEAA to become effective on January 1, 2012.  NPC filed an application to change its quarterly DEAA in October 2011.  NPC requested the first quarterly adjustment to the DEAA to become effective on April 1, 2012.

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

             EEIR

In 2009, the 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.  Accordingly, as of August 1, 2010, the Utilities began recording the amount of additional revenues which are objectively determinable and probable of recovery and are attributable to reduced kWh sales related to energy efficiency programs, prior to their inclusion in rates in accordance with FASC 980-605-25, Alternative Revenue Programs.

In October 2010, the Utilities filed to set 2011 base rates effective mid 2011 to recover approximately $35.1 million and $7.6 million for NPC and SPPC, respectively, for estimated reduced kWh sales related to the Utilities’ energy efficiency programs.  Annually, thereafter, the Utilities will make a filing 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.In May 2011, the PUCN issued a final order on the October 2010 filing authorizing increases to the base rates of $14.5 million and $2.6 million for NPC and SPPC, respectively, effective July 1, 2011.  As a result of the May order in June 2011, NPC and SPPC recorded a pre-tax adjustment to earnings for revenue previously recorded of approximately $4.5 million and $4.1 million, respectively.  As of September 30, 2011, NPC and SPPC have recognized 2011 revenues of approximately $10.4 million and $4.1 million, respectively, of the authorized EEIR base amounts of which $7.4 million and $1 million, respectively, were recognized in accordance with FASC 980-605-25, Alternative Revenue Programs discussed above.

In March 2011, the Utilities filed applications with their annual DEAA filings to reset the base rates and clear the accumulated regulatory asset accounts between August 1, 2010 and December 31, 2010, with rates effective in October 2011.  Reference further discussion below at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filing.

   EEPR

In addition, the regulation approved the transition of the recovery of energy efficiency 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 requested to set base rates beginning mid 2011 to recover the 2011 costs of implementing energy efficiency program costs of approximately $71.0 million and $12.1 million for NPC and SPPC, respectively.  In May 2011, the PUCN issued a final order authorizing increases to the base rates of $58.4 million and $9.7 million for NPC and SPPC, respectively, effective July 1, 2011.  For the three and nine months ended September 30, 2011, NPC and SPPC have recorded $20.5 million and $2.6 million respectively, of EEPR revenues.  Costs accumulated between August 1, 2010 and December 31, 2010 were requested for recovery in the March 2011 DEAA filing with rates effective October 2011. Reference further discussion below at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filing.

      Ely Energy Center

In February 2011, NVE and the Utilities cancelled plans to construct the EEC due to increasing environmental and economic uncertainties.  In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC.  Simultaneously, the Utilities filed a new UEPA application for the construction of a transmission line which was granted in May 2011.  The PUCN had previously approved the Utilities spending on development costs for the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $65.3 million as of September 30, 2011.  Management believes the development amounts expended through September 30, 2011 are probable of recovery.  In compliance with the SPPC 2010 Electric GRC, SPPC filed a separate

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application concurrent with the filing of NPC’s GRC filed in June 2011, to determine the reasonableness of the EEC project development costs and propose reclassification of these costs from a deferred debit to a regulatory asset.

     Nevada Power Company

   NPC 2011 GRC

In June 2011, NPC filed its statutorily required triennial GRC and updated the filing in August 2011.  In this updated filing, NPC is requesting the following:

• Increase in general rates by $249.9 million;

• ROE and ROR of 11.25% and 8.64%, respectively;

• Recovery of approximately $638.7 million, excluding AFUDC, for the 500 MW (nominally rated) expansion at the Harry Allen Generating Station;

• Authorization to defer collection of approximately $79.7 million of the requested rate increase as a regulatory asset in order to mitigate the impact on customers.  The remaining requested increase of approximately $170.2 is expected to be effective on January 1, 2012.

Testimony from intervening parties was filed with the PUCN in September and October. Hearings began in October and are scheduled to conclude in early November.  A decision is expected in December 2011.

           NPC 2011 DEAA, TRED, REPR, EEIR, EEPR Rate Filings

In March 2011, NPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR).  In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $78.6 million.  The PUCN authorized  recovery of the following amounts (dollars in millions):

		Authorized				Present			$ Change in
	Effective	Revenue				Revenue			Revenue
	Date	Requirement				Requirement			Requirement
Revenue Requirement Subject To Change:
DEAA	Oct. 2011	$	(188.9	)		$	(101.0	)	$	(87.9	)
REPR	Oct. 2011		8.6				29.8			(21.2	)
TRED	Oct. 2011		18.1				16.3			1.8
EEPR Base	Oct. 2011		58.4				58.4			-
EEPR Amortization	Oct. 2011		21.3				-			21.3
EEIR Base	Oct. 2011		17.1				14.5			2.6
EEIR Amortization	Oct. 2011		4.8		(1)		-			4.8
Total Revenue Requirement		$	(60.6	)		$	18.0		$	(78.6	)

(1) In accordance with Alternative Revenue Accounting, NPC has recognized approximately $4.8 million in revenues pertaining to 2010.  Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, NPC does not expect to record further revenue from this rate request; however, NPC does expect to collect approximately $4.8 million from its customers.

NPC Harry Allen Regulatory Asset Filing

In December 2010, NPC filed a petition with the PUCN seeking permission to establish a regulatory asset related to the 500 MW (nominally rated) expansion at the Harry Allen Generating Station.  The petition sought to recover approximately $40 million of foregone return, depreciation expense and incremental operating and maintenance expense incurred between June 1, 2011, the approved in service date, and December 31, 2011, which due to regulatory lag will not be recovered.  In April 2011, the PUCN denied NPC’s petition to establish a regulatory asset.  NPC does not plan further action on this request.

     Sierra Pacific Power Company

        SPPC 2011 Electric DEAA, TRED, REPR, EEIR, EEPR Rate Filings

In March 2011, SPPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR).  In September 2011, the PUCN accepted

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stipulations which resulted in an overall decrease in revenue requirement of approximately $8.2 million.  The PUCN authorized recovery of the following amounts (dollars in millions):

		Authorized				Present			$ Change in
	Effective	Revenue				Revenue			Revenue
	Date	Requirement				Requirement			Requirement
Revenue Requirement Subject To Change:
DEAA	Oct. 2011	$	(115.9	)		$	(99.5	)	$	(16.4	)
REPR	Oct. 2011		38.0				36.6			1.4
TRED	Oct. 2011		9.1				7.9			1.2
EEPR Base	Oct. 2011		9.7				9.7			-
EEPR Amortization	Oct. 2011		4.6				-			4.6
EEIR Base	Oct. 2011		3.1				2.6			0.5
EEIR Amortization	Oct. 2011		0.5		(1)		-			0.5
Total Revenue Requirement		$	(50.9	)		$	(42.7	)	$	(8.2	)

(1) In accordance with Alternative Revenue Accounting, SPPC has recognized approximately $0.5 million in revenues pertaining to 2010.  Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, SPPC does not expect to record further revenue from this rate request; however, SPPC does expect to collect approximately $0.5 million from their customers.

         SPPC 2011 Nevada Gas DEAA

In March 2011, SPPC filed an application to create a new DEAA rate to refund over-collected gas costs and to establish a new STPR (Solar Thermal Prospective Rate) to recover a legislatively mandated solar thermal program.   In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of $12.1 million.  The PUCN authorized the recovery of the following amounts (dollars in millions):

		Authorized				Present				$ Change in
	Effective	Revenue				Revenue				Revenue
	Date	Requirement				Requirement				Requirement
Revenue Requirement Subject To Change:
DEAA	Oct. 2011		$	(29.1	)		$	(16.7	)		$	(12.4	)
STPR	Oct. 2011			0.3				-				0.3
Total Revenue Requirement			$	(28.8	)		$	(16.7	)		$	(12.1	)

   FERC Matters

California Wholesale Spot Market Refunds

NPC and SPPC are participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001.  Both of the Utilities made spot market sales that are eligible for mitigation.  NPC and SPPC have negotiated a comprehensive settlement with the California parties and have joined in requesting that the FERC approve the settlement agreement.  The date by which parties may comment or protest the joint offer of settlement has passed and no party has tendered any form of opposition.   A FERC order on the joint offer of settlement is anticipated by December 2011.  The settlement is not material to the financial statements as a whole.

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NOTE 4.                      LONG-TERM DEBT

   Maturities of Long-Term Debt

As of September 30, 2011, 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):

	NVE			NVE
	Consolidated			Holding Co.		NPC			SPPC
2011(1)	$	(1,034	)	$	-	$	(1,034	)	$	-
2012		134,822			-		134,822			-
2013		285,405			-		35,405			250,000
2014		128,513			-		128,513			-
2015		251,039			-		251,039			-
Total Debt 2011-2015		798,745			-		548,745			250,000
Thereafter		4,388,183			506,500		2,965,266			916,417
Total Debt Before Unamortized Premium (Discount)		5,186,928			506,500		3,514,011			1,166,417
Unamortized Premium (Discount) Amount		(12,557	)		-		(25,828	)		13,271
Total Debt	$	5,174,371		$	506,500	$	3,488,183		$	1,179,688

(1) Amounts may differ from current portion of long-term debt as reported on the consolidated balance sheet due to the timing difference of payments and the change in obligation.

Substantially all utility plant is subject to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage bonds are issued.

Financing Transactions

   NV Energy, Inc.

$195 Million Term Loan Agreement

On October 7, 2011, NVE entered into a $195 million 3-year loan agreement (Term Loan).  The Term Loan is an unsecured, single-draw loan that is due on October 7, 2014.  The borrowing under the Term Loan will bear interest at the LIBOR rate plus a margin. The current LIBOR rate margin is 2.00%.   The margin varies based upon NVE’s long-term unsecured debt credit rating by S&P and Moody’s.  However, NVE entered into a floating-for-fixed interest rate swap agreement to lock in an effective interest rate of 2.81% for the length of the Term Loan.

The Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants. The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter ending on and after September 30, 2011, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter ending on and after September 30, 2011, to be less than 1.50 to 1.00.

Redemption of 6.75% Senior Notes

On October 7, 2011, NVE provided notice of the redemption of all of its $191.5 million 6.75% Senior Notes due 2017 (the "Senior Notes").  On November 7, 2011, NVE expects to use the proceeds of the Term Loan, plus cash on hand, to redeem the Senior Notes.  The Senior Notes will be redeemed at 102.25% of the stated principal amount plus accrued interest to the date of redemption.   Upon redemption, NVE and the Utilities will no longer be subject to the covenants contained in the Senior Notes, which were more restrictive than the covenants described above for the Term Loan.

Nevada Power Company

5.45% General and Refunding Mortgage Notes, Series Y

On May 12, 2011, NPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Y, due May 15, 2041.  The approximately $248 million in net proceeds, plus a portion of the proceeds from a draw on NPC’s revolving credit facility, were utilized to pay at maturity NPC’s $350 million aggregate principal amount of 8.25%  General and Refunding Mortgage Notes, Series A, which matured on June 1, 2011.   In conjunction with this debt issuance, NPC entered into an interest rate swap

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hedging agreement with a notional principal amount of $250 million and a mandatory termination date of June 1, 2011.  The interest rate swap agreement was entered into to effectively lock the interest rate of the U.S. Treasury component of the prospective General and Refunding Note issuance.  The swap transaction was settled on May 9, 2011, when NPC launched and priced the Series Y Notes, resulting in a settlement payment amount of $14.9 million, which was recorded as a regulatory asset and will be amortized over the 30 year life of the Series Y Notes in accordance with past accounting precedent for the Utilities.

NOTE 5.                       FAIR VALUE OF FINANCIAL INSTRUMENTS

The September 30, 2011 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable 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, 2011, is estimated to be $6.0 billion 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 was estimated to be $5.7 billion as of December 31, 2010.

The total fair value of NPC’s consolidated long-term debt at September 30, 2011, is estimated to be $4.1 billion 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 was estimated to be $3.9 billion at December 31, 2010.

The total fair value of SPPC’s consolidated long-term debt at September 30, 2011, is estimated to be $1.3 billion 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 was estimated to be $1.3 billion as of December 31, 2010.

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 accounting 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 mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

Interest Rate Risk

In August 2009, NPC entered into two interest rate swap agreements which terminated in June 2011, for an aggregated notional amount of $350 million associated with its $350 million 8.25% General and Refunding Mortgage Notes, Series A, due June 1, 2011.  Interest rate hedges manage existing and future fixed rate interest rate exposure with a variable interest rate in order to lower overall borrowing costs.  The interest rate swaps terminated in the second quarter of 2011 in conjunction with the payment at maturity of NPC’s $350 million 8.25% General and Refunding Mortgage Notes, Series A, due 2011, see Note 4, Long-Term Debt.

 On October 7, 2011, NVE entered into a floating for fixed interest rate swap in conjunction with its 3-year Term Loan to lock in an effective interest rate of 2.81% for the length of the Term Loan and manage existing and future variable rate interest rate exposure with fixed interest rate.  See Note 4, Long-Term Debt.

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Determination of Fair Value

As required by the Fair Value Measurements and Disclosure Topic of the FASC, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Risk management assets and liabilities in the recurring fair value measures table below may 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 and liabilities for NVE, NPC and SPPC were as follows (dollars in millions):

Option Premiums
	September 30, 2011								December 31, 2010
	NVE			NPC			SPPC		NVE			NPC			SPPC
Current Assets	$	0.1		$	0.1		$	-	$	1.9		$	1.4		$	0.5
Current Liabilities	$	(0.3	)	$	(0.3	)	$	-	$	(0.4	)	$	(0.4	)	$	-
Non-Current Liabilities		(0.2	)		(0.2	)		-		-			-			-
Total Liabilities	$	(0.5	)	$	(0.5	)	$	-	$	(0.4	)	$	(0.4	)	$	-

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.  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, 2011, 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, 2011									December 31, 2010
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC
Risk management assets - current	$	-		$	-		$	-		$	2.1		$	2.1		$	-
Risk management liabilities - current		1.2			0.9			0.3			32.9			22.4			10.5
Risk management liabilities - noncurrent		0.3			0.3			-			-			-			-
Total risk management liabilities		1.5			1.2			0.3			32.9			22.4			10.5
Risk management regulatory assets/liabilities – net (1)	$	(1.5	)	$	(1.2	)	$	(0.3	)	$	(30.8	)	$	(20.3	)	$	(10.5	)

(1) When amount is negative it represents a risk management regulatory asset, when positive it represents a risk management regulatory liability.  For the three months ended September 30, 2011, NVE, NPC and SPPC would have recorded cumulative gains of $3.5million, $2.9million and $0.6million, respectively, and for the nine months ended September 30, 2011, NVE, NPC and SPPC would have recorded gains of $29.3million, $19.1million, and $10.2million, respectively.  However, as permitted by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains, which are included in the risk management regulatory liability - net 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 liabilities decreased as of September 30, 2011, as compared to December 31, 2010, due to settlements of derivative contracts and the suspension of the Utilities’ hedging program as of October 2009.

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

September 30, 2011

December 31, 2010

Commodity Volume (MMBTU)

Commodity Volume (MMBTU)

NVE

NPC

SPPC

NVE

NPC

SPPC

Commodity volume liabilities - current (1)

0.6

0.5

0.1

18.1

12.9

5.2

(1) The change in commodity volumes at September 30, 2011, as compared to December 31, 2010, 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 plan covering substantially all employees of NVE and the Utilities.  NVE allocates the unfunded liability and the 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.  Certain grandfathered and union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.   A summary of the components of net periodic pension and other postretirement costs for the three and nine months ended September 30 follows.  This summary is based on a December 31, measurement date (dollars in thousands):

NVE
	Pension Benefits								Other Postretirement Benefits
		For the Three Months Ended September 30,							For the Three Months Ended September 30,
		2011			2010				2011			2010
Service cost		$	4,607		$	4,727			$	653		$	617
Interest cost			10,169			10,718				2,090			2,184
Expected return on plan assets			(12,192	)		(11,069	)			(1,596	)		(1,556	)
Amortization of prior service cost			(738	)		(448	)			(987	)		(972	)
Amortization of net loss			4,155			3,777				1,083			1,085
Net periodic benefit cost		$	6,001		$	7,705			$	1,243		$	1,358
	Pension Benefits							Other Postretirement Benefits
		For the Nine Months Ended September 30,							For the Nine Months Ended September 30,
			2011			2010				2011			2010
Service cost		$	13,820		$	14,182			$	1,958		$	1,850
Interest cost			30,507			32,154				6,270			6,551
Expected return on plan assets			(36,575	)		(33,206	)			(4,789	)		(4,667	)
Amortization of prior service cost			(2,214	)		(1,345	)			(2,961	)		(2,917	)
Amortization of net loss			12,465			11,329				3,250			3,256
Net periodic benefit cost		$	18,003		$	23,114			$	3,728		$	4,073
The average percentage of NVE net periodic costs capitalized during 2011 and 2010 was 33.26% and 33.85%, respectively.

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NPC
	Pension Benefits							Other Postretirement Benefits
		For the Three Months Ended September 30,							For the Three Months Ended September 30,
		2011			2010				2011			2010
Service cost		$	2,445		$	2,392			$	363		$	353
Interest cost			4,880			5,023				615			619
Expected return on plan assets			(6,169	)		(5,362	)			(590	)		(567	)
Amortization of prior service cost			(470	)		(433	)			229			236
Amortization of net loss			1,690			1,764				302			300
Net periodic benefit cost		$	2,376		$	3,384			$	919		$	941
	Pension Benefits							Other Postretirement Benefits
		For the Nine Months Ended September 30,							For the Nine Months Ended September 30,
			2011			2010				2011			2010
Service cost		$	7,336		$	7,175			$	1,090		$	1,060
Interest cost			14,640			15,069				1,844			1,856
Expected return on plan assets			(18,508	)		(16,085	)			(1,769	)		(1,702	)
Amortization of prior service cost			(1,409	)		(1,300	)			687			709
Amortization of net loss			5,069			5,292				906			899
Net periodic benefit cost		$	7,128		$	10,151			$	2,758		$	2,822
The average percentage of NPC net periodic costs capitalized during 2011 and 2010 was 37.18% and 36.34% respectively.

SPPC
	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended September 30,				For the Three Months Ended September 30,
	2011		2010		2011		2010
Service cost	$	1,840	$	2,004	$	271	$	245
Interest cost		5,013		5,389		1,457		1,547
Expected return on plan assets		(5,741)		(5,431)		(976)		(961)
Amortization of prior service cost		(277)		(26)		(1,219)		(1,213)
Amortization of net loss		2,412		1,969		773		777
Net periodic benefit cost	$	3,247	$	3,905	$	306	$	395
	Pension Benefits				Other Postretirement Benefits
	For the Nine Months Ended September 30,				For the Nine Months Ended September 30,
	2011		2010		2011		2010
Service cost	$	5,520	$	6,012	$	815	$	733
Interest cost		15,038		16,167		4,372		4,640
Expected return on plan assets		(17,223)		(16,292)		(2,929)		(2,883)
Amortization of prior service cost		(831)		(78)		(3,658)		(3,638)
Amortization of net loss		7,235		5,907		2,319		2,332
Net periodic benefit cost	$	9,739	$	11,716	$	919	$	1,184
The average percentage of SPPC net periodic costs capitalized during 2011 and 2010 was 31.22% and 34.57% respectively.

During the nine months ended September 30, 2011, the company made contributions totaling $10.0 million to the pension plan and no contributions to the other postretirement benefits plan.  At the present time, it is not anticipated that additional funding will be required for either plan in 2011 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2011 assumptions funding levels similar to the 2010 funding.  The amounts to be contributed in 2011 may change subject to market conditions.

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NOTE 8.                       COMMITMENTS AND CONTINGENCIES

Environmental

   NPC and SPPC

Regional Haze Rule Update

On June 22, 2011, the EPA filed notice in the Federal Register proposing to approve a revision to the Nevada State Implementation Plan (SIP) to implement the Regional Haze program, also known as the Best Available Retrofit Technology (BART) rule, for the first planning period extending through July 31, 2018.  Public comments on the proposed revision were received by the EPA in the third quarter of 2011.

The generating units subject to the BART rule are:  Reid Gardner units 1, 2 and 3 at NPC; and Tracy units 1, 2 and 3 and Fort Churchill units 1 and 2 at SPPC.

The Nevada BART rule will require a reduction in the nitrogen dioxide (NOx) emission rates for all affected units and specifies further reductions in sulfur dioxide (SO2) and particulate emissions from the units located at Tracy and Fort Churchill Generating Stations.   The current emission rates for SO2 and particulates at the Reid Gardner Generating Station are currently meeting the lower level BART requirements. Compliance with the new emission rules will be required by 2015 through a combination of fuel switching, installation of additional pollution controls, or retirement of individual units.  Management is currently assessing the impacts on the Utilities for these alternatives, while awaiting the final rule approval which is expected by year end.

   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.

      Reid Gardner Generating Station

On October 4, 2011, NPC 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 NPC’s Reid Gardner Generating Station located near Moapa, Nevada.  NPC operates the facility and owns Units 1-3.  Unit 4 of the facility is co-owned with the California Department of Water Resources.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  A first response is due back to the EPA in December 2011.  NPC has requested an extension from the EPA and is awaiting a decision on its extension request.  At this time, NPC cannot predict the impact, if any, associated with this information request.

   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 information request.

Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.  NVE and the Utilities continue to comply with these environmental commitments.  As of September 30, 2011, environmental expenditures did not change materially from those disclosed in the 2010 Form 10-K.

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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.

In October 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Company (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.   In April 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages.  Factual discovery was completed in October 2010, after which the parties engaged in settlement discussions. In April 2011, SCE indicated that it reached a settlement in the DC Lawsuit in principle. On August 1, 2011, the Navajo Nation, Peabody, Salt River and SCE executed a written settlement agreement in return for dismissal of all claims by the Navajo Nation. Salt River has asked that the Navajo Joint Owners, including NPC, contribute towards the settlement based on its 11% ownership stake in the Navajo plant. NPC has paid Salt River the requested contribution, which did not have a material impact on the financial statements.  SCE has asked that the Mohave Joint Owners, including NPC, contribute towards the settlement based upon their ownership stake in the Mohave plant. NPC has not agreed to pay SCE the requested contribution. Management continues to assess to what extent it should reimburse SCE, but does not believe the impact of such assessment will be material to NPC at this time.

   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 Company 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 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 three 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 and the Insurers opposed.   The Insurers time to file an appeal on the Court’s decision had been

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suspended pending the Court’s determination on the cash value reconsideration.  On July 10, 2009, the District 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. In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the Ninth Circuit. Subsequently, in August 2009, the Insurers appealed the District Court’s insurance coverage decision with the Ninth Circuit.  The Ninth Circuit heard arguments on the appeal in November 2010 and further asked that the parties consider mediation settlement proceedings. In January 2011, the parties, including TMWA, agreed to engage in mediation settlement discussions. Mediation was not successful, and the case was returned to the active docket for decision by the Ninth Circuit. At this time, SPPC filed a motion with the District Court to stay or toll the three-year replacement period. On June 15, 2011, the parties filed supplemental briefs concerning the cash value determination and the replacement cost of the dam. A decision by the Ninth Circuit is expected in the fourth quarter of 2011. Following the Ninth Circuit decision, the District Court is expected to decide on the motion concerning the replacement period.

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.

Other Commitments

   NPC and SPPC

      ON Line TUA

During the second quarter of 2011, NVE began to construct ON Line, which is Phase 1 of a joint project between the Utilities and GBT-South.  Construction of ON Line consists of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen Generating Station on the NPC system by late 2012.  The Utilities will own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line.  Under the terms of the TUA, NVE’s future lease payments are adjusted for construction costs, including cost overruns; therefore, for accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, NVE has capitalized construction costs, incurred as of September 30, 2011, associated with GBT’s 75% interest of approximately $110.0 million, or $105.2 and $4.8 million at NPC and SPPC, respectively, in CWIP with a corresponding credit to other deferred liabilities.  Total construction costs for Phase 1 of On Line is estimated to be $556 million, including AFUDC.

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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,
	2011		2010			2011		2010
Basic EPS
Numerator ($000)
Net Income	$	173,462	$	177,546	(2)	$	188,680	$	212,771	(2)
Denominator(1)
Weighted average number of common shares outstanding		235,990,373		235,117,058			235,796,321		234,991,208
Per Share Amounts
Net Income per share - basic	$	0.74	$	0.76	(2)	$	0.80	$	0.91	(2)
Diluted EPS
Numerator ($000)
Net Income	$	173,462	$	177,546	(2)	$	188,680	$	212,771	(2)
Denominator(1)
Weighted average number of shares outstanding before dilution		235,990,373		235,117,058			235,796,321		234,991,208
Stock options		33,343		35,973			36,314		30,818
Non-Employee Director stock plan		141,122		147,718			142,587		137,032
Employee stock purchase plan		4,012		9,463			4,547		6,186
Restricted Shares		146,464		87,613			123,940		69,322
Performance Shares		1,586,016		1,079,362			1,217,087		902,159
Diluted Weighted Average Number of Shares		237,901,330		236,477,187			237,320,796		236,136,725
Per Share Amounts
Net income per share - diluted	$	0.73	$	0.75	(2)	$	0.80	$	0.90	(2)

(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, 572,825 and 575,846 shares would be included for the three and nine months ended September 30, 2011, and 701,190 and 707,950 would be included for the three and nine months ended September 30, 2010, respectively.

(2)

As discussed in Note 1, Summary of Significant Accounting Policies, net income and earnings per share basic and diluted were reduced from that previously reported by $5.2 million (net of taxes) and $0.02 per share (net of taxes), respectively.

NOTE 10.                      ASSETS HELD FOR SALE

Nevada Power Company

      Sale of NPC’s Telecommunication Towers

In August 2011, NPC completed the sale of 37 telecommunication towers to Global Tower Partners, LLC.  Cash proceeds from the sale were approximately $32 million with the gain on sale deferred subject to the final accounting approval by the PUCN.

Sierra Pacific Power Company

       Sale of California Electric Distribution and Generation Assets

On January 1, 2011, SPPC completed the sale of its California electric distribution and generation assets to CalPeco, d/b/a Liberty Energy-CalPeco.  Cash proceeds from the sale were approximately $132 million, plus additional closing adjustments, resulting in an immaterial after tax gain, for which the final accounting was approved by the FERC in September 2011.  Refer to Note 16, Assets Held for Sale, of the Notes to Financial Statements of the 2010 Form 10-K for more information.

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NOTE 11.                      DIVIDENDS

Dividends

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

Declaration Date	Amount Per Share		Payable Date	Shareholders of Record Date
May 3, 2011	$	0.12	June 22, 2011	June 7, 2011
August 4, 2011	$	0.12	September 21, 2011	September 6, 2011
October 28, 2011	$	0.13	December 21, 2011	December 6, 2011

On May 3, 2011, NPC and SPPC declared dividends to NVE for $25 million and $12 million, respectively. On August 4, 2011, NPC and SPPC declared dividends to NVE for $40 million and $10 million, respectively.   On October 28, 2011, NPC declared a dividend to NVE for $34 million.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

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

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

(1)   economic conditions internationally, nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, 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, but not limited to GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, and energy efficiency recovery programs relating to the EEIR and EEPR;

(4)   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), current suspension of the 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;

(5)   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;

(6)   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;

(7)   wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

(8)   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: volatility in the global credit markets as a result of the viability of European sovereign debt or otherwise, 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;

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

(10)   changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;

(11)   the effect security breaches of our information technology systems or the systems of others  upon which the Utilities rely, whether through cyber-attack, cyber-terrorism, sabotage, accident or other means, may have on our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information;

(12)   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;

(13)   depending on their needs and analysis of the existing portfolio, 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;

(14)   the effect of existing or future Nevada, state or federal legislation or regulations affecting the electric industry,  including laws or regulations which could allow additional customers to choose new electricity suppliers, or use alternative sources of energy, or change the conditions under which they may do so;

(15)   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, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;

(16)   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;

(17)   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;

(18)   whether NVE's BOD will continue to declare NVE's common stock dividends based on the BOD’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in NVE's and the Utilities' agreements;

(19)   whether, following the Great Basin Water Network, et al. v. Nevada State Engineer litigation, certain permitted water rights of the SNWA that are used to supply water to the Utilities’ power production plants and service territories could be re-opened, which could adversely impact the operations of those plants and future growth and customer usage patterns;

(20)   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 and other post retirement plans, which can affect future funding obligations, costs and pension and other post retirement plan liabilities;

(21) 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;

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

(23)   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

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(24)   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 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.

NOTE REGARDING STATISTICAL DATA

The statistical data used throughout this Form 10-Q, other than data relating specifically to NVE and its subsidiaries, are based upon independent industry publications, government publications, reports by market research firms or other published independent sources.   NVE and the Utilities did not commission any of these publications or reports.  These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information.  While NVE and the Utilities believe that each of these studies and publications is reliable, NVE and the Utilities have not independently verified such data and make no representation as to the accuracy of such information.

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EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes discussion of the following:

• Critical Accounting Policies and Estimates:

• Recent Pronouncements

• For each of NVE, NPC and SPPC:

• Results of Operations

• Analysis of  Cash Flows

• Liquidity and Capital Resources

NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas.  The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas.  Other 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 $173.5 million and $188.7 million for the three and nine months ended September 30, 2011, respectively, compared to net income of $177.5 million and $212.8 million for the three and nine months ended September 30, 2010, respectively.   The decrease in net income for the three and nine months ended September 30, 2011, compared to the same periods in 2010, is primarily due to the completion of the expansion at the Harry Allen Generating Station in May 2011 which resulted in a decrease in AFUDC, an increase in depreciation expense and other operating and maintenance costs which are not currently recovered in rates.  Further contributing to the decrease in net income is a decrease in gross margin, excluding EEPR revenues and a loss from other investments.  Effective July 1, 2011, included in operating revenues were EEPR revenues, for which costs related to the program  are included in other operating expenses and therefore have no effect on operating income or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, for further discussion of EEPR revenues).  Net income for the nine month period decreased further due to an adjustment for revenue recorded in 2010, as a result of the PUCN’s final decision on the EEIR rate and the gain on sale of Independence Lake recognized in 2010.  Partially offsetting these decreases in net income was a favorable settlement with a vendor on a long term service agreement for the Higgins Generating Station, which was accrued for in the third quarter 2010.  Further offsetting the decrease in net income was a decrease in interest expense and reduced operating expenses, excluding EEPR costs.

During the third quarter 2010, NPC terminated a long term service agreement for one of its generating stations.  The estimated termination payment was not material to the third quarter but would have been material to the fourth quarter of 2010. Therefore, management determined it more appropriate to revise third quarter 2010 for the estimated termination payment.  As disclosed in our 2010 Form 10-K, Note 18, Quarterly Financial Data, of the Notes to Financial Statements, operating income, net income and earnings per share were reduced by $8.0 million, $5.2 million (net of taxes)  and $0.02 per share (net of taxes), share respectively.

The Utilities are regulated by the PUCN.  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 are primarily due to varying weather, customer growth and other energy usage patterns, including DSM programs and energy efficiency and conservation measures, which necessitate a continual balancing of loads and resources and purchases and sales of energy under short and long-term contracts.  As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities.  Additionally, the 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.

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Future Challenges

NVE and the Utilities must balance the needs of our customers and regulatory requirements while still continuing to provide value to our shareholders. Challenges arising from the need to balance these elements include:

 •  Economic conditions in Nevada and its effect on various interrelated factors, which include:

• customer growth;

• customer  usage;

• pressure on regulators to limit necessary rate increases or otherwise lessen rate impacts upon customers;

• load factors;

• future capital projects and capital requirements;

• managing operating and maintenance expenses within projected revenue without compromising safety, reliability and efficiency;

• our liquidity and ability to access capital markets;

• collections on accounts receivable; and

• counterparty risk.

• Meeting the Portfolio Standard, which requires that the Utilities obtain 15% of their energy from renewable resources in 2011 and 2012, increasing to 25% by 2025.

• Future execution of our three part strategy described below, including the impact of economic conditions, rate impacts on customers and any future legislative or regulatory requirements.

• Full and timely rate recovery of costs.

  Economic Conditions

In NPC’s service territory, which consists primarily of Las Vegas, key economic indicators, as outlined below, continue to show mixed activity:

• Unemployment in Las Vegas was at 14.2% in August 2011, down from 15.5% a year ago; 

• In southern Nevada, construction activity, another leading indicator, has experienced an increase in the number of commercial permits while residential permits have decreased in August 2011 compared to a year ago;

• Construction employment has decreased 10.0% as of August  2011 compared to a year ago;

• July 2011 taxable sales have increased 2.6%  from a year ago;

• August 2011 gaming revenues have decreased 6.7% from a year ago;

• August 2011 visitor volume increased 2.1% from a year ago; and

• August 2011 hotel/motel occupancy rate in Las Vegas has increased approximately 2.1% from a year ago.

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.

In SPPC’s service territory, which consists primarily of Washoe County, key economic indicators, as outlined below, continue to show mixed activity:

• Unemployment in Washoe County was at 13.0% in August 2011, down from 13.9% a year ago; however, much of the decline is a result of workers exiting the labor force;

• In Washoe County, residential permits have decreased, while commercial permits have increased in August 2011 compared to a year ago;

• Construction employment increased 2.0% as of August 2011, compared to a year ago 2010;

• July 2011 taxable sales increased 1.7% compared to a year ago; and

• August 2011 gaming revenues decreased 9.5% compared to a year ago.

The Portfolio Standard

The Portfolio Standard as set forth by Nevada law requires a specific percentage of an electric service provider’s total retail energy sales be obtained from renewable resources.  Renewables include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects.  In 2011 and 2012, the Utilities are required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables.  Currently, the Portfolio Standard increases to 18% for 2013 and 2014 and reaches 20% in

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2015 after which it increases to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond.  Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources until 2016 when a minimum of 6% must be solar.  The Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard.  The successful execution of the three part strategy, as discussed below, will be critical to our ability to meet the Portfolio Standard.

Three Part Strategy

The three part strategy which began in 2007 to manage resources against our load includes (1) encouraging energy efficiency and conservation programs, (2) the purchase and development of renewable energy projects, and (3) construction of generating facilities in an effort to reduce our reliance on purchased power and expansion of transmission capability.  The three part strategy continues to be the framework used to manage our resources against our load; however, the strategy has evolved as NVE has made progress on the goals included in the strategy.  This evolution includes (1) empower customers through more focused energy efficiency programs; (2) pursue cost-effective renewable energy  initiatives; (3) optimize generation efficiency; and (4) deliver lowest competitive price while maintaining and improving performance.

      Energy Efficiency and Conservation Programs

As stated above, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard.  Under this provision, a PEC is created for each kWh of energy conserved by qualified energy efficiency programs.  In addition, energy saved during peak demand hours earns double the PECs for each kWh of energy conserved.  After the DSM percentage allowance is fully utilized, NVE’s strategy is to assess economic conditions and potential rate impacts in pursuing the implementation of cost effective DSM programs needed to achieve future Portfolio Standard requirements.  As such, NVE remains committed to investing in such programs that qualify toward the Portfolio Standard, reduce our peak load, especially during peak periods, and are cost-effective.  NVE’s current 2011 budget includes approximately $67.5 million for energy efficiency and conservation programs.  Furthermore, the Utilities will continue with the implementation of NV Energize which will provide NVE with the Smart Grid infrastructure necessary to: (1) enable the achievement of metering and customer service operating savings; (2) enable the expansion of demand response and energy efficiency benefits; and (3) provide customers better information to help manage their energy usage.

       Purchase and Development of Renewable Energy Resources

 NVE continues to strive to balance the need to meet the Portfolio Standard, with the changes in load forecast and the uncertainty of renewable energy project development, either for financial or resource related reasons.  However, NVE remains committed to renewable energy and continues to seek cost effective opportunities that will benefit our state, customers and environment.  Depending on its needs and analysis of the existing portfolio, NVE may elect to issue requests for proposals for renewable energy contracts, explore opportunities to either jointly construct or pursue the development of projects using wind, geothermal and solar, or undertake additional short-term purchases.

       Construction of Generating and Transmission Facilities and Optimizing the Operation of Current Generation Assets

During the second quarter of 2011, NPC completed construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station.

In February 2011, NVE and the Utilities achieved Financial Closing under a TUA with GBT-South, formerly entered into with GBT, to jointly construct and own ON Line, a 500 Kv transmission line.  Construction of ON Line began in April 2011 and completion is expected in late 2012.  Upon completion, the ON Line will connect NVE’s southern and northern service territories and, pending certain state and federal regulatory approvals, will provide the ability to jointly dispatch energy throughout the state and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to meet its Portfolio Standard, discussed above, and lower costs to our customers.  In addition, NVE intends to file an application to merge the two Utilities with the PUCN by the end of 2011.

ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.  The Joint Project consists of two phases.  In Phase 1 of the Joint Project, the parties would complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen Generating Station on the NPC system by late 2012 (ON Line).  Under the Joint Project, the Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. The Utilities 25% interest in Phase 1 of the Joint Project, which approximates $127 million, will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of Phase 1, which is estimated to be approximately 600 MW.  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one extending from Robinson Summit north to Midpoint, Idaho, and the other commencing at the Harry Allen Generating Station and interconnecting south to the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.  However, NPC and SPPC

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would have rights to additional transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the complete path).

In 2011, NVE anticipates it will have sufficient resources to meet its forecasted load requirements.  However, resource adequacy could be affected by a number of factors, including the unplanned retirement of aging generating stations, the timing of commercial operation of renewable energy projects and associated PPA’s, customer behavior with respect to DSM programs, and environmental regulations which may limit our ability to operate certain generating units.  With consideration to these unpredictable factors, the current portfolio of generating assets and power contracts provides the Utilities the ability to provide a reliable level of energy supply.  NVE’s management continuously optimizes the Utilities’ energy portfolio in order to meet load obligations in a cost effective and reliable manner.

 Full and Timely Rate Recovery of Costs

The Utilities are required to file rate cases every three years to adjust general rates in order to recover their cost of service and return on investment.  The frequency of these filings is designed to more closely align earned returns with those allowed by regulators.  In addition, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement.  Historically, resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes.  Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases.  The Utilities remain focused on communicating with regulators the necessity of investments to better serve our customers, the prudency of the costs incurred, and the importance of a reasonable return on investment for our shareholders. 

NPC’s GRC was filed in June 2011, with new rates to become effective January 1, 2012.  A decision on the rate case is expected in late 2011.  One of the major elements in this GRC will be the inclusion in rate base of the new 500 MW (nominally rated) combined cycle natural gas generators at the site of the existing Harry Allen Generating Station, which was placed in service during the second quarter of 2011.    NPC’s investment in this facility (including AFUDC) as of September 30, 2011 was approximately $704 million. Management cannot predict future decisions on our rate cases, but believes the regulatory process, described above, coupled with prudent management provides a reasonable basis for the recovery of our investments.  An unfavorable ruling in NPC’s GRC with respect to its ability to recover its cost of service and return on investment could have a material adverse effect on our financial condition and results of operation.

2011 Goals

Management cannot predict when economic recovery may occur in Nevada, but expects that the Nevada economy will continue to struggle for the next several years.  As such, our primary goals will focus on meeting the challenges discussed above by:

• Continuing to monitor economic conditions in Nevada and adjusting our business decisions accordingly

• Building a sustainable foundation for future requirements by:

• Continuing to meet system deployment milestones in order to achieve NV Energize project completion by 2012

• Continued investment in energy efficiency and conservation programs

• Empower customers through more focused energy efficiency programs

• Pursue cost effective renewable energy initiatives

• Construction of ON Line

• Optimizing generation efficiency

• Deliver lowest competitive price while maintaining and improving performance

• Full and timely rate recovery of costs, in particular, NPC’s GRC filed in June 2011

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 $25.1 million and $29 million of interest costs for the nine months ended September 30, 2011 and 2010, respectively.

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During the nine months ended September 30, 2011, NPC had paid $65 million in dividends to NVE and SPPC had paid $114 million in dividends to NVE.

On October 28, 2011, NPC declared a dividend to NVE of $34 million.

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

NVE’s cash flows decreased during the nine months ended September 30, 2011, compared to the same period in 2010, due to a decrease in cash from operating and financing activities, offset partially by a reduction in cash used by investing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers, as well as a reduction in revenues from California customers due to the sale of the California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements.  Also contributing to this decrease was an increase in coal inventory for the Valmy Generating Station, increased incentive compensation payments for 2010 operating results, refund of customer deposits and an increase in conservation program costs and solar rebates.  These decreases were partially offset by an increase in cash resulting from NPC’s deferred rate increase beginning in October 2010, recovery of deferred conservation program costs and funding of retirement plans.

Cash Used By Investing Activities. The decrease in cash used by investing activities was primarily due to the decrease in general construction activity and activity related to the Harry Allen Generating Station which was placed in service in May 2011, and the receipt of proceeds from the sale of the California assets and the telecommunication towers, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements.  Further contributing to the decrease in cash used by investing activities was federal funding under the American Recovery Act of 2011, as part of the NV Energize project.

Cash Used By Financing Activities. Cash from financing activities decreased due to a reduction in draws on the Utilities’ revolving credit facilities, the redemption of NPC’s $350 million aggregate principal amount of 8.25% General and Refunding Mortgage Notes, Series A, which were partially paid by proceeds from the issuance of NPC’s $250 million 5.45% General and Refunding Mortgage Notes, Series Y, and a draw on the credit facility.

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, 2011 (in millions)
			NVE		NPC		SPPC
Cash and Cash Equivalents			$	32.9	$	34.8	$	66.3
	Balance available on Revolving Credit Facilities(1)			N/A		548.0		237.5
		Less Reduction for Hedging Transactions(2)		N/A		(1.7)		(0.5)
			$	32.9	$	581.1	$	303.3
(1)		As of October 31, 2011, NPC and SPPC had approximately $577.4 million and $237.2 million available under their revolving credit facilities,
		which includes reductions in availability for hedging transactions and letters of credit, as discussed further under NPC's
		and SPPC's Financing Transactions.
(2)		Reduction for hedging transactions reflects balances as of August 31, 2011.

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NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and 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 remaining in 2011; however, NPC’s $130 million 6.50% General and Refunding Mortgage Notes, Series I, will mature on April 15, 2012.  In addition, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected in late 2012.

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 and the use of their revolving credit facilities.    Furthermore, in order to fund long-term capital requirements and maturing debt obligations, NVE and the Utilities will 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 as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less.  In order to maintain sufficient liquidity, NVE and the Utilities may be required to delay capital expenditures (discussed in the 2010 Form 10-K), 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.  Additionally, 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 31, 2011, NVE has approximately $10.8 million payable of debt service obligations remaining for 2011, not including the redemption of the 6.75% Senior Notes discussed below, which it intends to pay through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries, below).  On January 4, 2011, NVE contributed $54 million in capital to NPC.  As of September 30, 2011, NPC and SPPC have paid  $65 million and $114 million, respectively, to NVE.  On October 28, 2011, NPC declared a dividend payable to NVE of $34 million.

NVE develops 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.

During the nine months ended September 30, 2011, there were no material changes to contractual obligations as set forth in NVE’s 2010 Form 10-K.  However, as discussed below, on October 7, 2011, NVE entered into a Term Loan.  See NPC's and SPPC's respective sections for changes in their contractual obligations.  

Financing Transactions

$195 Million Term Loan Agreement

On October 7, 2011, NVE entered into a $195 million 3-year loan agreement (Term Loan).  The Term Loan is an unsecured, single-draw loan that is due on October 7, 2014.  The borrowing under the Term Loan will bear interest at the LIBOR rate plus a margin. The current LIBOR rate margin is 2.00%.   The margin varies based upon NVE’s long-term unsecured debt credit rating by S&P and Moody’s.  However, NVE entered into a floating-for-fixed interest rate swap agreement to lock in an effective interest rate of 2.81% for the length of the Term Loan.

The Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants. The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter ending on and after September 30, 2011, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter ending on and after September 30, 2011, to be less than 1.50 to 1.00.

Redemption of 6.75% Senior Notes

On October 7, 2011, NVE provided notice of the redemption of all of its $191.5 million 6.75% Senior Notes due 2017 (the "Senior Notes").  On November 7, 2011, NVE expects to use the proceeds of the Term Loan, plus cash on hand, to redeem the Senior Notes.  The Senior Notes will be redeemed at 102.25% of the stated principal amount plus accrued interest to the date of redemption.   

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Upon redemption, NVE and the Utilities will no longer be subject to the covenants contained in the Senior Notes, which were more restrictive than the covenants described above for the Term Loan.

Factors Affecting Liquidity

   Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1.  Under this covenant restriction, as of September 30, 2011, NVE (consolidated) would be allowed to incur up to $2.1 billion of additional indebtedness, assuming an interest rate of 7%.  However, upon the redemption of NVE’s Senior Notes (see Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements), NPC would be subject to the financial covenants contained in NVE’s new Term Loan.  Under the new covenants, NVE (consolidated) would be allowed to incur up to $2.9 billion of additional indebtedness.

   Effect of Holding Company Structure

As of September 30, 2011, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: $191.5 million of its unsecured 6.75% Senior Notes due 2017, which NVE intends to redeem as of November 7, 2011; and $315 million of its unsecured 6.25% Senior Notes due 2020.  In addition, as discussed above, on October 7, 2011, NVE entered into a Term Loan for $195 million.

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, 2011, NVE, NPC, SPPC and their subsidiaries had approximately $5.2 billion of debt and other obligations outstanding, consisting of approximately $3.5 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $507 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.

Certain NVE debt agreements contain covenants that limit the amount of restricted payments, including dividends that may be made by NVE.  However, because permitted payments under these covenant calculations exceed retained earnings, NVE’s retained earnings were effectively free from any dividend restrictions as of September 30, 2011.

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

   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.   On March 11, 2011, S&P upgraded

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NVE’s senior unsecured debt to BB+.  On May 10, 2011, Moody’s upgraded NVE’s senior unsecured debt to Ba2.  As of September 30, 2011, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NVE		Sr. Unsecured Debt	BB	Ba2	BB+
NPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
SPPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

            A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  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, which includes a credit rating downgrade of 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, 2011 for all suppliers continuing to provide power under a WSPP agreement would approximate a $53.3 million payment or obligation to NPC.  No amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under 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 forward 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 a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.  NPC recently executed contracts for additional gas transportation capacity with this counterparty.  The maximum amount of additional collateral NPC would be required to post in the event NPC’s senior unsecured debt falls below BB (S&P) or Ba3(Moody’s) is $19.5 million.  The maximum amount of additional collateral NPC would be required to post in the event NPC’s senior secured debt is downgraded by both Moody’s and S&P below investment grade is $45.2 million.

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   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 net 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, 2011 was approximately $1.7 million and $0.5 million, respectively, which amount was in effect for borrowings during the month of September 2011. Currently, the Utilities only have hedging transactions with counterparties who are also lenders on the revolving credit facilities; however, future transactions executed with non-lenders may require the Utilities to post cash collateral in the event of a credit rating downgrade.  Finally, in October 2009, the Utilities suspended their hedging program, and as such, expect their exposure to negative mark-to-market hedging transactions to continue to decline.

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 an 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 $154.6 million during the three months ended September 30, 2011, compared to net income of approximately $158.9million for the same period in 2010.  During the nine months ended September 30, 2011, NPC recognized net income of approximately $161.7 million compared to a net income of approximately $176.4 million for the same period in 2010.

During the nine months ended September 30, 2011, NPC paid $65 million in dividends to NVE, and on October 28, 2011, NPC declared a dividend to NVE of approximately $34 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, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

	Three Months Ended September 30,								Nine Months Ended September 30,
						Change from								Change from
	2011			2010		Prior Year %			2011			2010		Prior Year %
Operating Revenues:	$	798,914		$	870,950		(8.3	)%	$	1,662,880		$	1,836,144		(9.4	)%
Energy Costs:
Fuel for power generation		162,976			181,100		(10.0	)%		378,790			469,282		(19.3	)%
Purchased power		181,733			216,309		(16.0	)%		399,707			412,276		(3.0	)%
Deferred energy		(10,354	)		22,296		(146.4	)%		(1,274	)		81,719		(101.6	)%
	$	334,355		$	419,705		(20.3	)%	$	777,223		$	963,277		(19.3	)%
Gross Margin	$	464,559		$	451,245		3.0	%	$	885,657		$	872,867		1.5	%

Gross margin increased for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to the implementation of the EEPR revenue, which became effective July 1, 2011 and a slight increase in customer growth for residential and commercial classes. However, costs related to EEPR are recorded in other operating expense, therefore, EEPR revenue does not have an effect on operating income or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).   Partially offsetting this increase was decreased usage among retail customers primarily due to milder weather.

Gross margin increased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to the implementation of the EEIR and EEPR rates, which became effective August 1, 2010 and July 1, 2011 respectively and a slight increase in customer growth for residential and commercial classes.  However, as stated above, EEPR revenue does not have an effect on operating income or net income as costs associated with the rate are recorded in other operating expense (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).  Further contributing to the increase in gross margin is a small increase in industrial usage.  Partially offsetting this increase was decreased usage among residential and commercial classes primarily due to milder weather.

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):

Electric Operating Revenue
	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2011		2010		Prior Year %			2011		2010		Prior Year %
Residential	$	426,827	$	459,483		(7.1	)%	$	824,378	$	897,417		(8.1	)%
Commercial		118,599		131,805		(10.0	)%		304,911		339,327		(10.1	)%
Industrial		236,452		261,534		(9.6	)%		485,347		548,901		(11.6	)%
Retail  revenues		781,878		852,822		(8.3	)%		1,614,636		1,785,645		(9.6	)%
Other		17,036		18,128		(6.0	)%		48,244		50,499		(4.5	)%
Total Operating Revenues	$	798,914	$	870,950		(8.3	)%	$	1,662,880	$	1,836,144		(9.4	)%
Retail sales in thousands of MWhs		7,100		7,208		(1.5	)%		16,121		16,255		(0.8	)%
Average retail revenue per MWh	$	110.12	$	118.32		(6.9	)%	$	100.16	$	109.85		(8.8	)%

NPC’s retail revenues decreased for the three months ended September 30, 2011, as compared to the same period in 2010 primarily due to decreased energy rates from NPC’s various BTER quarterly updates and the annual deferred energy case effective October 1, 2010 (See Note 3, Regulatory Actions, of the Condensed Notes to the Financial Statements and in the 2010 Form 10-K). Residential retail revenues decreased further due to decreases in customer usage resulting from milder temperatures during the summer months of 2011. These decreases were partially offset by EEPR revenue, effective July 1, 2011 (See Note 3, Regulatory Actions, of the Condensed Notes to the Financial Statements).  However, as noted in the discussion of Gross Margin, costs related to EEPR revenues are recorded in other operating expense, therefore, have no effect on operating income or net income.  For the three months ended September 30, 2011, the average number of residential and commercial customers increased by 1.1% and 0.7%, respectively, while industrial customers decreased by 2.9%.

NPC retail revenues decreased for the nine months ended September 30, 2011 as compared to the same period in 2010 primarily due to the reasons discussed above and the expiration of the Western Energy Crisis Amortization rate on May 1, 2010. The

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decrease was partially offset by EEPR revenue effective July 1, 2011, as discussed above, and by EEIR revenue, effective August 1, 2010 (See Note 3, Regulatory Actions, of the Condensed Notes to the Financial Statements and in the 2010 Form 10-K).  For the nine months ended September 30, 2011, the average number of residential and commercial customers increased by 1.1% and 0.5%, respectively, while industrial customers decreased by 1.7%.

Electric Operating Revenues – Other decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010 primarily due to decreased revenue from Public Street and Highway Lighting, resulting from lower energy rates.

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

• Mandated power purchases; and

• Volatility of commodity prices

	Three Months Ended September 30,							Nine Months Ended September 30,
					Change from							Change from
	2011		2010		Prior Year %			2011		2010		Prior Year %
Energy Costs
Fuel for power generation	$	162,976	$	181,100		(10.0	)%	$	378,790	$	469,282		(19.3	)%
Purchased power		181,733		216,309		(16.0	)%		399,707		412,276		(3.0	)%
Energy Costs	$	344,709	$	397,409		(13.3	)%	$	778,497	$	881,558		(11.7	)%
MWhs
MWhs Generated (in thousands)		4,879		4,738		3.0	%		11,138		11,868		(6.2	)%
Purchased Power (in thousands)		2,520		2,804		(10.1	)%		5,821		5,211		11.7	%
Total MWhs		7,399		7,542		(1.9	)%		16,959		17,079		(0.7	)%
Average cost per MWh
Average fuel cost per MWh of Generated Power	$	33.40	$	38.22		(12.6	)%	$	34.01	$	39.54		(14.0	)%
Average cost per MWh of Purchased Power	$	72.12	$	77.14		(6.5	)%	$	68.67	$	79.12		(13.2	)%
Average total cost per MWh	$	46.59	$	52.69		(11.6	)%	$	45.90	$	51.62		(11.1	)%

Energy Costs decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010 primarily due to a decrease in hedging costs. Volume decreased for the three months ended September 30, 2011 primarily due to the milder weather. The average cost per MWh for energy costs decreased primarily due to decreased hedging costs.

● Fuel for power generation costs decreased for the three and nine months ended September 30, 2011 primarily due to a decrease in hedging costs. Volume increased for the three months ended September 30, 2011 primarily due to increased internal generation. Volume decreased for the nine months ended September 30, 2011 primarily due to outages within the generation fleet earlier in the year.  The average price per MWh decreased for the three and nine months primarily due to a decrease in hedging costs and a decrease in market prices.

● Purchased power costs decreased for the three and nine months ended September 30, 2011 primarily due to a decrease in hedging costs related to tolling and a decrease in market prices. For the three and the nine months ended September 30, 2011 the average cost per MWh decreased primarily due to lower hedging costs related to tolling. Volume for the three months ended September 30, 2011 decreased primarily due to increased internal generation as the result of completion of the expansion at the Harry Allen Generating Station in May 2011. Volume for the nine months ended September 30, 2011 increased primarily due to planned outages within the generation fleet earlier in the year.

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Deferred Energy
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Deferred energy	$	(10,354)	$	22,296	(146.4)%	$	(1,274)	$	81,719	(101.6)%

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, 2011 and 2010 include amortization of deferred energy of $(28) million and $5.4 million, respectively; and an over-collection of amounts recoverable in rates of $17.7 million and $16.9 million, respectively.  Amounts for the nine months ended September 30, 2011 and 2010 include amortization of deferred energy of $(67) million and $20.7 million, respectively; and an over-collection of amounts recoverable in rates of $65.7 million and $61 million, respectively.

Other Operating Expenses
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Other operating expenses	$	88,455	$	73,762	19.9%	$	215,491	$	203,773	5.8%
Maintenance	$	3,460	$	23,707	(85.4)%	$	45,122	$	58,945	(23.5)%
Depreciation and amortization	$	67,212	$	56,575	18.8%	$	186,798	$	169,330	10.3%

Other operating expense increased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to an increase in energy efficiency program costs and stock compensation costs.  However, as noted above in Gross Margin, energy efficiency program costs are recovered through EEPR and therefore, have no effect on operating income or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).  The increase in other operating expense was partially offset by higher capitalization of administrative general costs for the Harry Allen Generating Station and lower overall generating expense, consulting fees and employee pension and benefit costs.

Maintenance expense decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to the accrual in 2010 for estimated payments for the termination of long term service agreements for the Higgins and Lenzie Generating Stations, which, in the case of the Higgins Generating Station, was reversed in the third quarter of 2011 upon final calculation of the termination amount.  Also contributing to the decrease in maintenance expense was planned maintenance outages that occurred in 2010 at the Higgins Generating Station. This decrease was partially offset by planned maintenance outages that occurred at the Reid Gardner Generating Station.

Depreciation and amortization increased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to general increases in plant-in-service balances, including the addition of Harry Allen Combined Cycle Plant, EWAM, and transmission and distribution infrastructure.

Interest Expense
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Interest expense (net of AFUDC-debt: $842,
$5,787, $8,962 and $15,763)	$	55,267	$	54,144	2.1%	$	163,036	$	161,496	1.0%

Interest expense increased for the three and nine months ended September 30, 2011 compared to the same period in 2010 primarily due to a decrease in AFUDC due to the completion of various construction projects, including the expansion at the Harry Allen Generating Station and EWAM projects.  Also contributing to the increase was the issuance of $250 million, Series X, General and Refunding Mortgage Notes in September 2010 and the issuance of $250 million, Series Y, General and Refunding Mortgage

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Notes in May 2011.  Partially offsetting the increase was a decrease in interest expense due to the redemption of the $350 million Series A General and Refunding Mortgage Notes in June 2011, partial redemptions of Series 1995 A, B, C, and D tax exempt bonds in October 2010 and lower credit facility balances in 2011.

Other Income (Expense)
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Interest expense on regulatory items	$	(2,478)	$	(1,157)	114.2%	$	(5,911)	$	(1,965)	200.8%
AFUDC-equity	$	1,026	$	6,795	(84.9)%	$	10,979	$	18,555	(40.8)%
Other income	$	2,990	$	3,842	(22.2)%	$	9,298	$	9,084	2.4%
Other expense	$	(7,324)	$	(3,034)	141.4%	$	(15,235)	$	(9,338)	63.2%

The change in interest expense on regulatory items for the three and nine months ended September 30, 2011, compared to the same period in 2010, is primarily due to higher over-collected deferred energy balances in 2011.  See Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

AFUDC-equity decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to the completion of various construction projects, including the expansion at the Harry Allen Generation Station and EWAM projects.

Other income for the three months ended September 30, 2011, decreased over the same period in 2010 primarily due to lower gains on investments, partially offset by higher carrying charges for energy conservation programs.

Other income for the nine months ended September 30, 2011, increased over the same period in 2010 primarily due to higher carrying charges for energy conservation programs, partially offset by lower gains on investments.

Other expense for the three months ended September 30, 2011, increased over the same period in 2010, primarily due to losses on investments, and higher adjustments for a deferred energy settlement in 2011.

Other expense for the nine months ended September 30, 2011, increased over the same period in 2010, primarily due to the disallowance for EEIR, an adjustment for a deferred energy settlement, losses on investments, and higher donations, partially offset by adjustments made in 2010 for excess power purchases and a deferred energy settlement.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during the nine months ended September 30, 2011, compared to the same period in 2010, due to a decrease in cash from operating and financing activities, offset partially by a reduction in cash used by investing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers, increased incentive compensation payments for 2010 operating results, refunds of customer deposits and an increase in conservation programs and solar rebates.  These decreases were partially offset by an increase in cash resulting from NPC’s deferred rate increase beginning in October 2010, the recovery of deferred conservation program costs and retirement plan funding.

Cash Used By Investing Activities. The decrease in cash used by investing activities was primarily due to the decrease in construction activity related to the Harry Allen Generating Station which was placed in service in May 2011, proceeds from the sale of the telecommunication towers and federal funding under the American Recovery Act of 2011 as part of the NV Energize project.

Cash From Financing Activities. Cash from financing activities decreased primarily due to a reduction in draws on NPC’s revolving credit facility, the redemption of NPC’s $350 million aggregate principal amount of 8.25%, Series A, General and Refunding Mortgage Notes, which were partially paid by proceeds from the issuance of NPC’s $250 million 5.45%, Series Y, General and Refunding Mortgage Notes.  Also contributing to the decrease was the payment of dividends to NVE and a settlement payment for the interest rate swap agreement as discussed in Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements.  The decrease was partially offset by a capital contribution from NVE.

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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, 2011 (in millions)
			NPC
Cash and Cash Equivalents			$	34.8
	Balance available on Revolving Credit Facility(1)			548.0
		Less Reduction for Hedging Transactions(2)		(1.7)
			$	581.1
(1)		As of October 31, 2011, NPC had approximately $577.4 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 transactions reflects balances as of August 31, 2011.

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 facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, 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 remaining in 2011; however, NPC’s $130 million 6.50% General and Refunding Mortgage Notes, Series I, will mature on April 15, 2012.  In addition, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected in late 2012.  As of October 31, 2011, NPC has no borrowings on its revolving credit facility, not including letters of credit.

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds and the use of its revolving credit facility.  Furthermore, in order to fund long-term capital requirements and maturing debt obligations, NPC will 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 and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less.  In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures (discussed in the 2010 Form 10-K), re-finance debt or obtain funding through an equity or debt 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.  Additionally, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

On January 4, 2011, NPC received a capital contribution of approximately $54 million from NVE.  During the nine months ended September 30, 2011, NPC paid dividends to NVE of $65 million.On October 28, 2011, NPC declared a dividend to NVE of $34 million.

NPC develops 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.

During the nine months ended September 30, 2011, there were no material changes to contractual obligations as set forth in NPC’s 2010 Form 10-K, except for the issuance of its 5.45% General and Refunding Mortgage Notes, Series Y, discussed below.

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Financing Transactions

   5.45% General and Refunding Mortgage Notes, Series Y

On May 12, 2011, NPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Y, due May 15, 2041.  The approximately $248 million in net proceeds, plus a portion of the proceeds from a draw on NPC’s revolving credit facility, were utilized to pay at maturity NPC’s $350 million aggregate principal amount of 8.25%  General and Refunding Mortgage Notes, Series A, which matured on June 1, 2011.   In conjunction with this debt issuance, NPC entered into an interest rate swap hedging agreement with a notional principal amount of $250 million and a mandatory termination date of June 1, 2011.  The interest rate swap agreement was entered into to effectively lock the interest rate of the U.S. Treasury component of the prospective General and Refunding Note issuance.  The swap transaction was settled on May 9, 2011, when NPC launched and priced the Series Y Notes, resulting in a settlement payment amount of $14.9 million, which was recorded as a regulatory asset and will be amortized over the 30 year life of the Series Y Notes in accordance with past accounting precedent for the Utilities.

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 its revolving credit facility agreement, and the terms of certain NVE debt.  As of September 30, 2011, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725 million in long-term debt, in addition to the use of its existing credit facility.  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:

a.	Financing authority from the PUCN - As of September 30, 2011, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion;
b.	Financial covenants within NPC’s financing agreements – Under its $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, 2011 financial statements, NPC was in compliance with this covenant and could incur up to $2.7billion of additional indebtedness;
	All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently 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 $2.1 billion.However, upon the redemption of NVE’s Senior Notes (see Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements), NPC would be subject to the financial covenants contained in NVE’s new Term Loan.  Under the new covenants, NVE (consolidated) would be allowed to incur up to $2.9 billion of additional indebtedness.

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

The Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of September 30, 2011, $4 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.4 billion of additional General and Refunding Mortgage Securities as of September 30, 2011.  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.

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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 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 NPC Indenture.

   $600 Million Revolving Credit Facility

NPC’s $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 reduction in availability under the revolving credit facility to NPC shall not exceed 50% of the total commitments then in effect under the revolving credit facility.

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 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.

   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.  On May 10, 2011, Moody’s upgraded NPC’s senior secured debt to Baa2.  As of September 30, 2011, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

            A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  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, which includes 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

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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, 2011 for all suppliers continuing to provide power under a WSPP agreement would approximate a $53.3 million payment or obligation to NPC.  These contracts qualify for the normal purchases scope exception under 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 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 a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.  NPC recently executed contracts for additional gas transportation capacity with this counterparty.  The maximum amount of additional collateral NPC would be required to post in the event NPC’s senior unsecured debt falls below BB (S&P) or Ba3(Moody’s) is $19.5 million.  The maximum amount of additional collateral NPC would be required to post in the event NPC’s senior secured debt is downgraded by both Moody’s and S&P below investment grade is $45.2 million.

   Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts.  As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is reduced by the amount of net 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 30, 2011 was approximately $1.7 million, which amount was in effect for borrowings during the month of September 2011.  Currently, NPC only has hedging transactions with counterparties who are also lenders on the revolving credit facility; however, future transactions executed with non-lenders may require NPC to post cash collateral in the event of a credit rating downgrade.  Finally, in October 2009, NPC suspended its hedging program, and as such, expects its exposure to negative mark-to-market positions to continue 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 $25.3 million for the three months ended September 30, 2011, compared to net income of $24.5 million for the same period in 2010.  During the nine months ended September 30, 2011, SPPC recognized net income of approximately $45.4 million compared to $52.9 million for the same period in 2010.

During the nine months ended September 30, 2011, SPPC paid $114 million in dividends to NVE.

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

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which SPPC calculates as operating revenues less 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, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

		Three Months Ended September 30,					Nine Months Ended September 30,
						Change from					Change from
		2011		2010		Prior Year %	2011		2010		Prior Year %
Operating Revenues:
	Electric	$	202,263	$	237,798	(14.9)%	$	545,462	$	649,337	(16.0)%
	Gas		16,615		19,286	(13.8)%		125,357		139,711	(10.3)%
		$	218,878	$	257,084	(14.9)%	$	670,819	$	789,048	(15.0)%
Energy Costs:
	Fuel for power generation		53,803		66,133	(18.6)%		141,130		181,232	(22.1)%
	Purchased power		41,615		33,545	24.1%		118,965		110,262	7.9%
	Gas purchased for resale		10,137		10,823	(6.3)%		87,753		101,536	(13.6)%
	Deferral of energy - electric - net		(22,095)		9,964	(321.7)%		(45,924)		17,189	(367.2)%
	Deferral of energy - gas - net		(1,171)		1,795	(165.2)%		3,520		7,646	(54.0)%
		$	82,289	$	122,260	(32.7)%	$	305,444	$	417,865	(26.9)%
Gross Margin by Segment:
	Electric		128,940		128,156	0.6%		331,291		340,654	(2.7)%
	Gas		7,649		6,668	14.7%		34,084		30,529	11.6%
Gross Margin		$	136,589	$	134,824	1.3%	$	365,375	$	371,183	(1.6)%

Electric gross margin increased slightly for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to increased rates, particularly for commercial and industrial customers, as a result of SPPC’s GRC effective January 1, 2011.  Also contributing to the increase was EEPR revenue, which became effective July 1, 2011.  However, costs related to EEPR are recorded in other operating expense; therefore, EEPR revenue does not have an effect on operating income or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).  The increase in gross margin was partially offset by the sale of the California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements.  Further contributing to the decrease was increased gross margin in 2010 as a result of an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1999-1.

Electric gross margin decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to the sale of the California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements, partially offset by a related five year power sale agreement entered into as a condition to the sale of the assets.  Further contributing to the decrease was increased gross margin in 2010 as a result of an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1999-1. In addition, reduced Distribution Only Service impact fees in 2011 contributed to the decrease in margin.  Partially offsetting this decrease is increased rates, particularly for commercial and industrial customers, as a result of SPPC’s GRC effective January 1, 2011, increased usage in residential and industrial customer classes, as well as, the implementation of the EEPR rate, which became effective July 1, 2011.  However, costs related to EEPR are recorded in other operating expense; therefore, EEPR revenue does not have an effect on operating income or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).

Gas gross margin increased for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to a slight BTGR increase as a result of SPPC’s 2010 GRC effective January 1, 2011.

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Gas gross margin increased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to increased usage as a result of colder temperatures and a slight BTGR increase as a result of SPPC’s 2010 GRC effective January 1, 2011.

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

Electric Operating Revenue
			Three Months Ended September 30,					Nine Months Ended September 30,
							Change from					Change from
			2011		2010		Prior Year %	2011		2010		Prior Year %
	Residential		$	63,402	$	81,638	(22.3)%	$	178,445	$	234,274	(23.8)%
	Commercial			75,503		93,150	(18.9)%		200,064		250,647	(20.2)%
	Industrial			46,761		51,398	(9.0)%		116,396		138,280	(15.8)%
		Retail  Revenues		185,666		226,186	(17.9)%		494,905		623,201	(20.6)%
	Other			16,597		11,612	42.9%		50,557		26,136	93.4%
		Total Operating Revenues	$	202,263	$	237,798	(14.9)%	$	545,462	$	649,337	(16.0)%
Retail sales in thousands of MWhs				2,076		2,192	(5.3)%		5,725		6,075	(5.8)%
Average retail revenue per MWh			$	89.43	$	103.19	(13.3)%	$	86.45	$	102.58	(15.7)%

SPPC’s retail revenues decreased for the three and nine months ended September 30, 2011 as compared to the same periods in 2010, due to decreases in retail rates as a result of SPPC’s annual deferred energy case effective October 1, 2010, and various BTER quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 Form 10-K).  Retail revenues also decreased due to the sale of the California assets on January 1, 2011 (see Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements). These decreases were offset by a slight increase in rates due to SPPC’s 2010 GRC effective January 1, 2011.  For the three months ended September 30, 2011, excluding California customers, the average number of retail and commercial customers increased by 0.3% and 0.1%, respectively, while industrial customers decreased by 4.2%. For the nine months ended September 30, 2011, excluding California customers, the average number of retail and commercial customers increased by 0.3% and 0.8%, respectively, while industrial customers decreased by 1.8%.

Electric Operating Revenues – Other increased for the three and nine months ended September 30, 2011, compared to the same periods in 2010, primarily due to the sale of energy to CalPeco, under a five year agreement, as a condition to the sale of SPPC’s California assets which occurred on January 1, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements.

Gas Operating Revenue
			Three Months Ended September 30,					Nine Months Ended September 30,
							Change from					Change from
			2011		2010		Prior Year %	2011		2010		Prior Year %
Gas Operating Revenues:
	Residential		$	8,582	$	9,953	(13.8)%	$	65,833	$	72,699	(9.4)%
	Commercial			3,398		4,617	(26.4)%		27,945		34,014	(17.8)%
	Industrial			1,265		1,784	(29.1)%		8,634		11,228	(23.1)%
		Retail  Revenues		13,245		16,354	(19.0)%		102,412		117,941	(13.2)%
	Wholesale Revenues			2,615		2,408	8.6%		20,530		19,976	2.8%
	Miscellaneous			755		524	44.1%		2,415		1,794	34.6%
		Total Gas Revenues	$	16,615	$	19,286	(13.8)%	$	125,357	$	139,711	(10.3)%
Retail sales in thousands of Dths				1,187		1,272	(6.7)%		10,593		10,108	4.8%
Average retail revenue per Dth			$	11.16	$	12.86	(13.2)%	$	9.67	$	11.67	(17.1)%

SPPC’s retail gas revenues decreased for the three and nine months ended September 30, 2011, compared to the same periods in 2010, primarily due to decreased retail rates as a result of SPPC’s various BTER quarterly updates and 2010 Natural Gas and Propane Deferred Rate Case effective October 1, 2010 (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 Form 10-K). These decreases were partially offset by increased customer usage resulting from colder 2011 temperatures, during the nine month period, and a slight BTGR increase as a result of SPPC’s 2010 GRC effective January 1, 2011. The average number of retail customers increased by 0.6% and 0.7%, respectively, for the three and nine months ended September 30, 2011.

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Wholesale revenues increased for the three and nine months ended September 30, 2011, compared to the same periods in 2010 primarily due to the sale of gas as a result of the optimization of pipeline capacity.

Energy Costs

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

● Weather

● Plant outages

● Total system demand

● Resource constraints

● Transmission constraints

● Gas transportation constraints

● Natural gas constraints

● Long-term contracts

● Mandated power purchases; and

● Generation efficiency

		Three Months Ended September 30,					Nine Months Ended September 30,
						Change from					Change from
		2011		2010		Prior Year %	2011		2010		Prior Year %
Energy Costs
	Fuel for power generation	$	53,803	$	66,133	(18.6)%	$	141,130	$	181,232	(22.1)%
	Purchased power		41,615		33,545	24.1%		118,965		110,262	7.9%
Total Energy Costs		$	95,418	$	99,678	(4.3)%	$	260,095	$	291,494	(10.8)%
MWhs
	MWhs Generated (in thousands)		1,301		1,525	(14.7)%		3,339		3,825	(12.7)%
	Purchased Power (in thousands)		1,057		767	37.8%		3,260		2,643	23.3%
Total MWhs			2,358		2,292	2.9%		6,599		6,468	2.0%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	41.36	$	43.37	(4.6)%	$	42.27	$	47.38	(10.8)%
	Average cost per MWh of Purchased Power	$	39.37	$	43.74	(10.0)%	$	36.49	$	41.72	(12.5)%
	Average total cost per MWh	$	40.47	$	43.49	(7.0)%	$	39.41	$	45.07	(12.5)%

Energy costs decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to a decrease in hedging costs and market prices partially offset by higher volumes.  Total system demand for the three and nine months ended September 30, 2011, as compared to the same period in 2010, increased primarily due to the hotter weather.  The average cost per MWh decreased primarily due to a decrease in hedging costs and lower market prices.

• Fuel for generation costs and volumes decreased for the three and nine months ending September 30, 2011, compared to the same period in 2010, primarily due to a decrease in hedging costs and outages at the Valmy Generating Station. The average costs per MWh for the three and nine months ended September 30, 2011, decreased primarily due to a decrease in hedging activities, as well as a decrease in natural gas prices.

• Purchased power costs and volume increased for the three and nine months ending September 30, 2011 compared to the same period in 2010, primarily due to the outages discussed above, as well as hotter weather, partially offset by a decrease in market prices. The average price per MWh for the nine months ended September 30, 2011, decreased primarily due to lower market prices.   

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Gas Purchased for Resale
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Gas purchased for resale	$	10,137	$	10,823	(6.3)%	$	87,753	$	101,536	(13.6)%
Gas purchased for resale (in thousands of Dths)		1,859		1,867	(0.4)%		15,696		14,759	6.3%
Average cost per Dth	$	5.45	$	5.80	(5.9)%	$	5.59	$	6.88	(18.7)%

Gas purchased for resale and the average cost per Dth decreased for the three and nine months ended September 30, 2011, as compared to the same period in 2010 primarily due to decreased hedging costs.  Volume increased for the nine months ended September 30, 2011, as compared to the same period in 2010 due to colder weather and an increase in the purchase of gas in an effort to optimize pipeline capacity.

Deferred Energy
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Deferral of energy - electric - net	$	(22,095)	$	9,964	(321.7)%	$	(45,924)	$	17,189	(367.2)%
Deferral of energy - gas - net		(1,171)		1,795	(165.2)%		3,520		7,646	(54.0)%
	$	(23,266)	$	11,759		$	(42,404)	$	24,835

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, 2011 and 2010 reflect amortization of deferred energy costs of ($27.1) million and ($6.1) million, respectively; and an over-collection of amounts recoverable in rates of $5.0 million and $16.1 million, respectively.  For the nine months ended September 30, 2011 and 2010, amortization of deferred energy was ($75.5) million and ($17.3) million, respectively; with an over-collection of amounts recoverable in rates of $29.5 million and $34.5 million, respectively.

Deferred energy – gas for the three months ended September 30, 2011 and 2010 reflect amortization of deferred energy of ($1.3) million, and ($0.7) million, respectively; and an over-collection of amounts recoverable in rates of $0.2 million and $2.5 million, respectively.  For the nine months ended September 30, 2011 and 2010, amortization of deferred energy was ($12.0) million and ($5.9) million, respectively; with an over-collection of amounts recoverable in rates of $15.5 million and $13.5 million, respectively.

Other Operating Expenses
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Other operating expenses	$	38,529	$	38,004	1.4%	$	113,432	$	114,371	(0.8)%
Maintenance	$	7,909	$	7,419	6.6%	$	28,195	$	26,770	5.3%
Depreciation and amortization	$	26,525	$	26,848	(1.2)%	$	79,647	$	79,737	(0.1)%

Other operating expense increased for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to regulatory amortizations, energy efficiency program costs and stock compensation costs.  However, as discussed in Gross Margin, energy efficiency program costs are recovered by the EEPR and therefore have no effect on operating or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).  These increases were partially offset by lower outside consulting fees and rate case expenses.

Other operating expense decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to lower outside consulting fees, lease expense, an increase in capitalized administrative and general expenses and

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employee pension and benefits expenses, partially offset by regulatory amortizations, energy efficiency program costs and stock compensation costs.  However, as discussed in Gross Margin, energy efficiency program costs are recovered by the EEPR and therefore have no effect on operating or net income (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements).

Maintenance expense increased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to a scheduled major outage at the Valmy and Ft. Churchill Generating Stations; partially offset by the 2010 combustion turbine maintenance at the Tracy Generating Station.

Depreciation and amortization decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010, primarily due to a change in depreciation rates effective January 1, 2011.

Interest Expense
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2011		2010		Prior Year %	2011		2010		Prior Year %
Interest expense (net of AFUDC-debt: $484,
$698, $1,409 and $1,586)	$	16,861	$	16,983	(0.7)%	$	50,581	$	51,141	(1.1)%

Interest expense decreased for the three and nine months ended September 30, 2011 compared to the same period in 2010 primarily due to the redemption of $100 million Series H General and Refunding Mortgage Bonds in December 2010. See Note 6, Long-Term Debt, of the Notes to Financial Statements of the 2010 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)
	Three Months Ended September 30,						Nine Months Ended September 30,
					Change from						Change from
	2011		2010		Prior Year %		2011		2010		Prior Year %
Interest expense on regulatory items	$	(1,838)	$	(2,528)	(27.3)	%	$	(6,229)	$	(6,788)	(8.2)	%
AFUDC-equity	$	664	$	1,029	(35.5)	%	$	1,875	$	2,360	(20.6)	%
Other income	$	1,448	$	2,379	(39.1)	%	$	4,677	$	14,276	(67.2)	%
Other expense	$	(2,255)	$	(1,285)	75.5	%	$	(7,403)	$	(7,555)	(2.0)	%

Interest expense on regulatory items decreased for the three and nine months ended September 30, 2011, compared to the same period in 2010, is due to lower over-collected deferred energy balances in 2011.

AFUDC-equity decreased for the three and nine months ended September 30, 2011 compared to the same period in 2010, primarily due to the completion of various construction projects, including EWAM.

Other income for the three months ended September 30, 2011, decreased over the same period in 2010, primarily due to a decrease in income from subleases and lower interest income on investments.

Other income for the nine months ended September 30, 2011, decreased over the same period in 2010, primarily due to the gain on sale for the Independence Lake property in 2010, as further discussed in Note 10, Assets Held for Sale of the Notes to Financial Statements, and a decrease in income from subleases.

Other expense for the three months ended September 30, 2011, increased over the same period in 2010, primarily due to losses on investments in 2011, and adjustments for the settlement of the deferred energy rate case, see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 Form 10-K for further details.

Other expense for the nine months ended September 30, 2011, decreased over the same period in 2010, primarily due to a decrease in lease expense and charitable donations, partially offset by an adjustment, upon final order from the PUCN in the second quarter of 2011, for EEIR revenue recorded in 2010 and adjustments for the settlement of the deferred energy rate case, see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further details.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows decreased during the nine months ended September 30, 2011, compared to the same period in 2010, due to a decrease in cash from operating activities and an increase in cash used for financing activities, offset partially by an increase in cash from investing.

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Cash From Operating Activities. The decrease in cash from operating activities was primarily due to an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers.  Also contributing to the decrease is the reduction in revenues from California customers due to the sale of the California Assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements, an increase in coal inventory for the Valmy Generating Station, an increase in conservation and renewable energy program costs and increased incentive compensation payments for the 2010 operating results.  These decreases were partially offset by the recovery of deferred conservation program costs as a result of SPPC’s 2010 GRC.

Cash From Investing Activities. Cash from investing activities increased due to the receipt of proceeds from the sale of the California Assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements.  Also contributing to the increase in cash from investing activities was the decrease in general construction for infrastructure, which was partially offset by federal funding under the American Recovery Act of 2011, as part of the NV Energize project.

Cash Used By Financing Activities. The increase in cash used by financing activities is primarily due to increased dividends 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, 2011 (in millions)
			SPPC
Cash and Cash Equivalents			$	66.3
	Balance available on Revolving Credit Facility(1)			237.5
		Less Reduction for Hedging Transactions(2)		(0.5)
			$	303.3
(1)		As of October 31, 2011, SPPC had approximately $237.2 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 transactions reflects balances as of August 31, 2011.

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 facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, 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 either 2011 or 2012.  As of October 31, 2011, SPPC has no borrowings on its revolving credit facility, not including letters of credit.

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds and the use of its revolving credit facility.  Furthermore, in order to fund long-term capital requirements and maturing debt obligations, SPPC will 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 SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less.  In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures (discussed in the 2010 Form 10-K), refinance debt or obtain funding through an equity or debt 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.  Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

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During the nine months ended September 30, 2011, SPPC paid dividends to NVE of $114 million.

SPPC develops 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.

During the nine months ended September 30, 2011, there were no material changes to contractual obligations as set forth in SPPC’s 2010 Form 10-K.

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, 2011, 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, 2011, 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 – Under SPPC’s $250 million revolving credit facility, the Utility 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, 2011 financial statements, SPPC was in compliance with this covenant and could incur up to $851 million of additional indebtedness;
	All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently 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 $2.1 billion.However, upon the redemption of NVE’s Senior Notes (see Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements), SPPC would be subject to the financial covenants contained in NVE’s new Term Loan.  Under the new covenants, NVE (consolidated) would be allowed to incur up to $2.9 billion of additional indebtedness.

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

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of September 30, 2011, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $742 millionof additional General and Refunding Mortgage Securities as of September 30, 2011.  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.

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SPPC also has the ability to release property from the lien of the SPPC Indenture on the basis of net property additions, cash and/or retired bonds.  To the extent SPPC releases property from the lien of SPPC’s Indenture, it will reduce the amount of securities issuable under the SPPC Indenture.

   $250 Million Revolving Credit Facility

SPPC’s $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 reduction in the availability under the revolving credit facility to SPPC shall not exceed 50% of the total commitments then in effect under the revolving credit facility.

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 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.

   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 NRSROs: Fitch, Moody’s and S&P.  On May 10, 2011, Moody’s upgraded SPPC’s senior secured debt to Baa2.  As of September 30, 2011, the ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB*	Baa2*	BBB*
	*Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  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, which includes 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

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liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  Under the net mark-to-market value as of September 30, 2011 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 under 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, 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.

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.

   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 net 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, 2011 was approximately $0.5 million, which amount was in effect for borrowings during the month of September 2011.  Currently, SPPC only has hedging transactions with counterparties who are also lenders on the revolving credit facility; however, future transactions executed with non-lenders may require SPPC to post cash collateral in the event of a credit rating downgrade.  Finally, in October 2009, SPPC suspended its hedging program, and as such, expects its exposure to negative mark-to-market positions to continue 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.

RECENT PRONOUNCEMENTS

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

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ITEM 3.                       QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2011, 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):

					2011
					Expected Maturities
																									Fair
				2011		2012			2013			2014			2015			Thereafter			Total				Value
Long-Term Debt
	NVE
	Fixed Rate			$	-	$	-		$	-		$	-		$	-		$	506,500		$	506,500		$	522,369
		Average Interest Rate			-		-			-			-			-			6.44	%		6.44	%
	NPC
	Fixed Rate			$	-	$	130,000		$	-		$	125,000		$	250,000		$	2,755,000		$	3,260,000		$	3,929,529
		Average Interest Rate			-		6.50	%		-			7.38	%		5.88	%		6.43	%		6.42	%
	Variable Rate			$	-	$	-		$	30,000		$	-		$	-		$	173,775		$	203,775		$	197,699
		Average Interest Rate			-		-			2.49	%		-			-			0.65	%		0.92	%
	SPPC
	Fixed Rate			$	-	$	-		$	250,000		$	-		$	-		$	701,742		$	951,742		$	1,132,203
		Average Interest Rate			-		-			5.45	%		-			-			6.27	%		6.05	%
	Variable Rate			$	-	$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	190,989
		Average Interest Rate			-		-			-			-			-			0.62	%		0.62	%		-
			TOTAL DEBT	$	-	$	130,000		$	280,000		$	125,000		$	250,000		$	4,351,692		$	5,136,692		$	5,972,789

Commodity Price Risk

See the 2010 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, 2010.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties.  Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition.  The Utilities’ credit risk associated with trading counterparties was approximately $55.7 million as of September 30, 2011, which compares to balances of $51.4 million at June 30, 2011. The increase from June 30, 2011 is primarily related to a long-term tolling contract.

ITEM 4.                      CONTROLS AND PROCEDURES

(a)   Evaluation of disclosure controls and procedures.

NVE’s, NPC’s and SPPC’s principal executive officer and principal financial officer, 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, 2011, the registrants’ disclosure controls and procedures were effective.

(b)   Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the third quarter of 2011 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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ITEM 1.                      LEGAL PROCEEDINGS

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 2010 Form 10-K.  The risks and uncertainties described below are not the only ones we face.  Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2010 Form 10-K, and quarterly reports for NVE, NPC and SPPC on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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

 None.

ITEM 3.                      DEFAULTS UPON SENIOR SECURITIES

 None.

ITEM 5.                      OTHER INFORMATION

 On October 28, 2011, NVE’s BOD approved two amendments to NVE’s By-laws, effectively immediately.  The first amendment, to Article IV of the By-laws, lowers the percentage of the voting power of the outstanding capital stock of the company required to call a special meeting of the stockholders from twenty-five percent to fifteen percent.  The second amendment, to Article VIII of the By-laws, provides that in uncontested elections of directors, the required vote for election will be a majority of the votes cast with respect to a particular director, which means that the number of shares voted for the director must exceed the number of shares voted against the director.  If a director in an uncontested election does not receive a majority of the votes cast with respect to that director, then that director must promptly tender his or her resignation.  The Nominating and Governance Committee will then consider the tendered resignation, taking into account certain specified factors, and will make a recommendation to the Board within 60 days following the election whether to accept the resignation or take other action.  Within 120 days following the election, the full Board must act on the Committee’s recommendation and must publicly disclose its decision, including the reasons for not accepting a resignation.  In contested elections, the required vote for election of directors will be a plurality of shares represented at the meeting and entitled to vote on the election of directors.

An amended and restated version of the By-laws, reflecting the foregoing amendments, is filed herewith as an exhibit.

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ITEM 6.                      EXHIBITS

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

(3)       NV Energy, Inc.

3.1 Bylaws of NV Energy, Inc., as amended through October 28, 2011.

(10)    NV Energy, Inc.

10.1 Loan Agreement dated October 7, 2011 by and among NV Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, and PNC Bank National Association and U.S. Bank National Association, as Co-Documentation Agents.

(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.

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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.

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

*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Schema
*101.CAL	XBRL Calculation Linkbase
*101.LAB	XBRL Label Linkbase
*101.PRE	XBRL Presentation Linkbase
*101.DEF	XBRL Definition Linkbase

*  XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

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SIGNATURES

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

	NV Energy, Inc.
	(Registrant)
Date:  November 2, 2011	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date:  November 2, 2011	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Nevada Power Company d/b/a NV Energy
	(Registrant)
Date:  November 2, 2011	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date:  November 2, 2011	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:  November 2, 2011	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date:  November 2, 2011	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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