UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 2012

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 6, 2012

Common Stock, $1.00 par value

of NV Energy, Inc.

235,414,553 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.

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION


Acronyms & Terms				3

ITEM 1.	Financial Statements

	NV Energy, Inc.
			Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2012 and 2011	5
			Consolidated Balance Sheets – September 30, 2012 and December 31, 2011	6
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	8
			Consolidated Statements of Shareholders’ Equity - Nine Months Ended September 30, 2012 and 2011	9
	Nevada Power Company
			Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2012 and 2011	10
			Consolidated Balance Sheets – September 30, 2012 and December 31, 2011	11
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	13
			Consolidated Statements of Shareholder’s Equity - Nine Months Ended September 30, 2012 and 2011	14
	Sierra Pacific Power Company
			Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2012 and 2011	15
			Consolidated Balance Sheets – September 30, 2012 and December 31, 2011	16
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	18
			Consolidated Statements of Shareholder’s Equity - Nine Months Ended September 30, 2012 and 2011	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	26
			Note 5. Fair Value of Financial Instruments	28
			Note 6. Retirement Plan and Post-Retirement Benefits	28
			Note 7. Commitments and Contingencies	30
			Note 8. Earnings per Share (NVE)	33
			Note 9. Common Stock and Other Paid-In Capital	33

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

	NV Energy, Inc.			41
	Nevada Power Company			45
	Sierra Pacific Power Company			56

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk			67

ITEM 4.	Controls and Procedures			68

PART II – OTHER INFORMATION

ITEM 1.		Legal Proceedings		69
ITEM 1A.		Risk Factors		69
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds		69
ITEM 3.		Defaults Upon Senior Securities		69
ITEM 4.		Mine Safety Disclosures		69
ITEM 5.		Other Information		69
ITEM 6.		Exhibits		70

Signature Page and Certifications				72

ACRONYMS AND TERMS

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


Acronym/Term		Meaning

2011 Form 10-K		NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2011
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
CA ISO		California Independent System Operator Corporation
California Assets		SPPC's California electric distribution and generation assets
CalPeco		California Pacific Electric Company
CDD		Cooling degree days
Clark Generating Station		550 MW nominally rated William Clark Generating Station
CWIP		Construction Work-in-Progress
dba		Doing business as
DEAA		Deferred Energy Accounting Adjustment
DSM		Demand Side Management
Dth		Decatherm
EEIR		Energy Efficiency Implementation Rate
EEPR		Energy Efficiency Program Rate
EPA		Environmental Protection Agency
EPS		Earnings per Share
FASB		Financial Accounting Standards Board
FASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd.
Ft. Churchill Generating Station		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, expanded in 2011 to 642 total MWs
HDD		Heating degree days
Higgins Generating Station		598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
kV		Kilovolt
Lenzie Generating Station		1,102 megawatt nominally rated Chuck Lenzie Generating Station
LIBOR		London Interbank Offered Rate
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
NOL		Net Operating Loss
NPC		Nevada Power Company d/b/a NV Energy
NPC Credit Agreement		$500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank,
		N.A., as administrative agent for the lenders a party thereto
NPC 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
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
Smart Meters		Advanced service delivery meters installed as part of the NV Energize project

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 March 2012 between SPPC and Wells Fargo
		Bank, N.A., as administrative agent for the lenders a party thereto
SPPC 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
STPR		Solar Thermal Program Rate
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

ITEM 1. FINANCIAL STATEMENTS

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands, Except Share Amounts)

(Unaudited)



		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2012		2011		2012		2011

OPERATING REVENUES		$	1,026,488	$	1,017,796	$	2,378,606	$	2,333,710

OPERATING EXPENSES:
	Fuel for power generation		171,316		216,779		400,936		519,920
	Purchased power		205,686		223,348		486,894		518,672
	Gas purchased for resale		5,382		10,137		46,491		87,753
	Deferred energy		(29,036)		(33,620)		(30,285)		(43,678)
	Energy efficiency program costs		32,584		23,047		76,609		23,047
	Other operating expenses		100,108		104,598		307,080		308,119
	Maintenance		19,014		11,369		76,190		73,317
	Depreciation and amortization		94,512		93,737		281,690		266,445
	Taxes other than income		15,682		15,205		44,457		46,134
Total Operating Expenses			615,248		664,600		1,690,062		1,799,729
OPERATING INCOME			411,240		353,196		688,544		533,981

OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,976, $1,326, $5,479 and $10,371)		(73,667)		(80,496)		(226,162)		(238,718)
	Interest income (expense) on regulatory items		(2,024)		(1,282)		(6,203)		(3,549)
	AFUDC-equity		2,415		1,690		6,666		12,854
	Other income		8,827		1,611		19,312		6,351
	Other expense		(4,209)		(9,857)		(11,909)		(23,600)
Total Other Income (Expense)			(68,658)		(88,334)		(218,296)		(246,662)
Income Before Income Tax Expense			342,582		264,862		470,248		287,319

Income tax expense			119,412		91,400		165,466		98,639

NET INCOME			223,170		173,462		304,782		188,680

Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization
(Net of taxes $(74), $(293), $(246) and $(1,302))			155		544		464		2,417
Change in market value of risk management assets and liabilities
(Net of taxes $91, $0, $355 and $0)			(193)		-		(668)		-

OTHER COMPREHENSIVE INCOME (LOSS)			(38)		544		(204)		2,417

COMPREHENSIVE INCOME		$	223,132	$	174,006	$	304,578	$	191,097

Amount per share basic and diluted - (Note 8)
	Net income per share - basic	$	0.95	$	0.74	$	1.29	$	0.80
	Net income per share - diluted	$	0.94	$	0.73	$	1.28	$	0.80
Weighted Average Shares of Common Stock Outstanding - basic			235,961,402		235,990,373		235,986,874		235,796,321
Weighted Average Shares of Common Stock Outstanding - diluted			238,121,732		237,901,330		237,850,530		237,320,796
Dividends Declared Per Share of Common Stock		$	0.17	$	0.12	$	0.47	$	0.36

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

NV ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)


			September 30,		December 31,
			2012		2011
ASSETS

Current Assets:
	Cash and cash equivalents		$	207,903	$	145,944
	Accounts receivable less allowance for uncollectible accounts:
		2012 - $9,750; 2011 - $8,150		511,107		355,091
	Materials, supplies and fuel, at average cost			147,984		129,663
	Current income taxes receivable			-		82
	Deferred income taxes			165,015		104,958
	Other current assets			47,172		36,782
Total Current Assets				1,079,181		772,520

Utility Property:
	Plant in service			12,074,285		11,923,717
	Construction work-in-progress			658,494		487,427
	Total			12,732,779		12,411,144
Less accumulated provision for depreciation				3,351,132		3,184,071
	Total Utility Property, Net			9,381,647		9,227,073

Investments and other property, net				58,666		57,021

Deferred Charges and Other Assets:
	Deferred energy (Note 3)			90,244		102,525
	Regulatory assets			1,121,185		1,186,127
	Regulatory asset for pension plans			207,137		215,656
	Other deferred charges and assets			77,999		74,206
Total Deferred Charges and Other Assets				1,496,565		1,578,514

TOTAL ASSETS			$	12,016,059	$	11,635,128


		(Continued)

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

			September 30,		December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY			2012		2011

Current Liabilities:
	Current maturities of long-term debt (Note 4)		$	258,024	$	139,985
	Accounts payable			322,940		312,990
	Accrued expenses			101,199		128,144
	Deferred energy (Note 3)			214,181		245,164
	Other current liabilities			68,172		65,572
Total Current Liabilities				964,516		891,855

Long-term debt (Note 4)				4,766,563		5,008,931

Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
	Deferred income taxes			1,546,998		1,306,510
	Deferred investment tax credit			14,109		16,140
	Accrued retirement benefits			79,405		92,351
	Regulatory liabilities			541,823		486,259
	Other deferred credits and liabilities			507,417		427,003
Total Deferred Credits and Other Liabilities				2,689,752		2,328,263

Shareholders' Equity:
	Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued
		for 2012 and 2011; 235,747,750 and 235,999,750 outstanding for 2012 and 2011, respectively		236,000		236,000
	Treasury stock, at cost, 252,000 shares and 0 shares for 2012 and 2011, respectively			(4,509)		-
	Other paid-in capital			2,713,736		2,713,736
	Retained earnings			658,139		464,277
	Accumulated other comprehensive loss			(8,138)		(7,934)
Total Shareholders' Equity				3,595,228		3,406,079

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$	12,016,059	$	11,635,128

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


(Concluded)

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


			For the Nine Months Ended
			September 30,
			2012		2011
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	304,782	$	188,680
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		281,690		266,445
		Deferred taxes and deferred investment tax credit		187,229		99,920
		AFUDC-equity		(6,666)		(12,854)
		Deferred energy		(18,702)		(20,802)
		Amortization of other regulatory assets		114,626		124,213
		Deferred rate increase		2,252		65,306
		Other, net		(50,012)		27,546
	Changes in certain assets and liabilities:
		Accounts receivable		(151,420)		(132,078)
		Materials, supplies and fuel		(18,034)		(26,290)
		Other current assets		(10,390)		(5,242)
		Accounts payable		22,646		32,397
		Accrued retirement benefits		(12,946)		167
		Other current liabilities		(23,643)		(37,869)
		Other deferred assets		(3,572)		(14,982)
		Other regulatory assets		34,420		(72,480)
		Other deferred liabilities		(8,066)		(15,043)
Net Cash from Operating Activities				644,194		467,034

CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(387,790)		(469,870)
		Proceeds from sale of asset		-		166,603
		Customer advances for construction		(1,508)		(7,159)
		Contributions in aid of construction		63,864		79,343
		Investments and other property - net		217		410
Net Cash used by Investing Activities				(325,217)		(230,673)

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		130,764		386,784
		Retirement of long-term debt		(272,353)		(480,689)
		Settlement of interest rate lock		-		(14,944)
		Sale of common stock		-		8,681
		Common stock repurchased		(4,509)		-
		Dividends paid		(110,920)		(84,907)
Net Cash used by Financing Activities				(257,018)		(185,075)

Net Increase in Cash and Cash Equivalents				61,959		51,286
Beginning Balance in Cash and Cash Equivalents				145,944		86,189
Ending Balance in Cash and Cash Equivalents			$	207,903	$	137,475

Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	237,262	$	251,011
		Income taxes	$	151	$	1
	Significant non-cash transactions:
		Accrued construction expenses as of September 30,	$	132,112	$	158,849

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

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)


													Accumulated
			Common	Common		Treasury		Treasury	Other				Other		Total
			Stock	Stock		Stock		Stock	Paid-in		Retained		Comprehensive		Shareholders'
			Shares	Amount		Shares		Amount	Capital		Earnings		Income (Loss)		Equity
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


December 31, 2011			235,999,750	$	236,000	-	$	-	$	2,713,736	$	464,277	$	(7,934)	$	3,406,079
	Net Income		-		-	-		-		-		304,782		-		304,782
	Change in compensation retirement benefits
		liability and amortization (net of taxes $(246))	-		-	-		-		-		-		464		464
	Change in market value of risk management
		assets and liabilities (net of taxes $355)	-		-	-		-		-		-		(668)		(668)
	Common stock repurchased		-		-	(252,000)		(4,509)		-		-		-		(4,509)
	Dividends Declared		-		-	-		-		-		(110,920)		-		(110,920)
September 30, 2012			235,999,750	$	236,000	(252,000)	$	(4,509)	$	2,713,736	$	658,139	$	(8,138)	$	3,595,228

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)



		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2012		2011		2012		2011

OPERATING REVENUES		$	802,334	$	798,914	$	1,751,165	$	1,662,880

OPERATING EXPENSES:
	Fuel for power generation		123,992		162,976		285,799		378,790
	Purchased power		171,687		181,733		388,494		399,707
	Deferred energy		(22,685)		(10,354)		(15,461)		(1,274)
	Energy efficiency program costs		28,492		20,451		65,466		20,451
	Other operating expenses		65,372		68,004		200,484		195,040
	Maintenance		12,533		3,460		52,594		45,122
	Depreciation and amortization		66,975		67,212		201,096		186,798
	Taxes other than income		9,743		9,105		26,793		28,209
Total Operating Expenses			456,109		502,587		1,205,265		1,252,843
OPERATING INCOME			346,225		296,327		545,900		410,037

OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,528, $842, $4,021 and $8,962)		(51,784)		(55,267)		(158,791)		(163,036)
	Interest income (expense) on regulatory items		(1,623)		(82)		(5,488)		679
	AFUDC-equity		1,833		1,026		4,823		10,979
	Other income		7,096		594		14,197		2,708
	Other expense		(2,823)		(7,324)		(7,162)		(15,235)
Total Other Expense			(47,301)		(61,053)		(152,421)		(163,905)
Income Before Income Tax Expense			298,924		235,274		393,479		246,132

Income tax expense			103,754		80,666		137,328		84,481

NET INCOME			195,170		154,608		256,151		161,651

Other comprehensive income:
Change in compensation retirement benefits liability and amortization
(Net of taxes $(33), $(41), $(103) and $(554))			65		75		192		1,028

COMPREHENSIVE INCOME		$	195,235	$	154,683	$	256,343	$	162,679


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

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)


			September 30,		December 31,
			2012		2011
ASSETS

Current Assets:
	Cash and cash equivalents		$	124,505	$	65,887
	Accounts receivable less allowance for uncollectible accounts:
		2012 - $8,514; 2011 - $6,751		397,954		233,096
	Materials, supplies and fuel, at average cost			77,919		72,529
	Deferred income taxes			132,663		88,782
	Other current assets			32,658		28,943
Total Current Assets				765,699		489,237

Utility Property:
	Plant in service			8,396,240		8,345,771
	Construction work-in-progress			519,218		352,541
		Total		8,915,458		8,698,312
	Less accumulated provision for depreciation			2,041,170		1,906,617
		Total Utility Property, Net		6,874,288		6,791,695

Investments and other property, net				51,875		50,768

Deferred Charges and Other Assets:
	Deferred energy (Note 3)			90,244		102,525
	Regulatory assets			820,372		852,989
	Regulatory asset for pension plans			104,053		108,528
	Other deferred charges and assets			59,060		46,855
Total Deferred Charges and Other Assets				1,073,729		1,110,897

TOTAL ASSETS			$	8,765,591	$	8,442,597


(Continued)

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


			September 30,		December 31,
			2012		2011
LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities:
	Current maturities of long-term debt (Note 4)		$	7,930	$	139,985
	Accounts payable			204,148		182,183
	Accounts payable, affiliated companies			42,915		28,429
	Accrued expenses			60,942		89,311
	Deferred energy (Note 3)			140,183		159,799
	Other current liabilities			54,133		50,725
Total Current Liabilities				510,251		650,432

Long-term debt (Note 4)				3,328,281		3,319,605

Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
	Deferred income taxes			1,187,617		997,921
	Deferred investment tax credit			4,976		6,098
	Accrued retirement benefits			13,163		9,454
	Regulatory liabilities			317,993		274,951
	Other deferred credits and liabilities			416,990		335,159
Total Deferred Credits and Other Liabilities				1,940,739		1,623,583

Shareholder's Equity:
	Common stock, $1.00 par value; 1,000 shares authorized
	issued and outstanding for 2012 and 2011			1		1
	Other paid-in capital			2,308,219		2,308,219
	Retained earnings			682,025		544,874
	Accumulated other comprehensive loss			(3,925)		(4,117)
Total Shareholder's Equity				2,986,320		2,848,977

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY			$	8,765,591	$	8,442,597

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


(Concluded)

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Nine Months Ended
			September 30,
			2012		2011
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	256,151	$	161,651
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		201,096		186,798
		Deferred taxes and deferred investment tax credit		150,289		85,488
		AFUDC-equity		(4,823)		(10,979)
		Deferred energy		(7,335)		14,651
		Amortization of other regulatory assets		56,012		62,994
		Deferred rate increase		2,252		65,306
		Other, net		(35,553)		19,889
Changes in certain assets and liabilities:
		Accounts receivable		(164,858)		(145,862)
		Materials, supplies and fuel		(5,119)		(9,100)
		Other current assets		(3,715)		(3,307)
		Accounts payable		53,985		26,434
		Accrued retirement benefits		3,708		3,971
		Other current liabilities		(25,246)		(32,523)
		Other deferred assets		(2,412)		(13,788)
		Other regulatory assets		50,008		(44,383)
		Other deferred liabilities		(10,412)		(16,676)
Net Cash from Operating Activities				514,028		350,564

CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(232,608)		(367,097)
		Proceeds from sale of asset		-		31,997
		Customer advances for construction		713		(2,165)
		Contributions in aid of construction		34,274		64,617
		Investments and other property - net		193		395
Net Cash used by Investing Activities				(197,428)		(272,253)

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		132,259		386,884
		Retirement of long-term debt		(271,241)		(464,575)
		Settlement of interest rate lock		-		(14,944)
		Additional investment by parent company		-		54,000
		Dividends paid		(119,000)		(65,000)
Net Cash used by Financing Activities				(257,982)		(103,635)

Net Increase (Decrease) in Cash and Cash Equivalents				58,618		(25,324)
Beginning Balance in Cash and Cash Equivalents				65,887		60,077
Ending Balance in Cash and Cash Equivalents			$	124,505	$	34,753

Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	177,459	$	182,992
		Income taxes	$	1	$	1
	Significant non-cash transactions:
		Accrued construction expenses as of September 30,	$	111,052	$	141,384

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

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, 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

December 31, 2011		1,000	$	1	$	2,308,219	$	544,874	$	(4,117)	$	2,848,977
	Net Income	-		-		-		256,151		-		256,151
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(103))	-		-		-		-		192		192
	Dividends Declared	-		-		-		(119,000)		-		(119,000)
September 30, 2012		1,000	$	1	$	2,308,219	$	682,025	$	(3,925)	$	2,986,320

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)



		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2012		2011		2012		2011
OPERATING REVENUES:
	Electric	$	212,073	$	202,263	$	549,886	$	545,462
	Gas		12,077		16,615		77,543		125,357
Total Operating Revenues			224,150		218,878		627,429		670,819

OPERATING EXPENSES:
	Fuel for power generation		47,324		53,803		115,137		141,130
	Purchased power		33,999		41,615		98,400		118,965
	Gas purchased for resale		5,382		10,137		46,491		87,753
	Deferral of energy - electric - net		(5,498)		(22,095)		(13,854)		(45,924)
	Deferral of energy - gas - net		(853)		(1,171)		(970)		3,520
	Energy efficiency program costs		4,092		2,596		11,143		2,596
	Other operating expenses		34,128		35,933		104,214		110,836
	Maintenance		6,481		7,909		23,596		28,195
	Depreciation and amortization		27,537		26,525		80,594		79,647
	Taxes other than income		5,894		6,052		17,382		17,675
Total Operating Expenses			158,486		161,304		482,133		544,393
OPERATING INCOME			65,664		57,574		145,296		126,426

OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $448, $484, $1,458 and $1,409)		(15,298)		(16,861)		(47,650)		(50,581)
	Interest expense on regulatory items		(401)		(1,200)		(715)		(4,228)
	AFUDC-equity		582		664		1,843		1,875
	Other income		1,399		810		4,181		2,676
	Other expense		(998)		(2,255)		(3,609)		(7,403)
Total Other Income (Expense)			(14,716)		(18,842)		(45,950)		(57,661)
Income Before Income Tax Expense			50,948		38,732		99,346		68,765

Income tax expense			16,521		13,396		33,596		23,341

NET INCOME			34,427		25,336		65,750		45,424

Other comprehensive income:
Change in compensation retirement benefits liability and amortization
(Net of taxes $(22), $(150), $(68) and $(1,201))			42		279		127		2,230

COMPREHENSIVE INCOME		$	34,469	$	25,615	$	65,877	$	47,654

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)


			September 30,		December 31,
			2012		2011
ASSETS

Current Assets:
	Cash and cash equivalents		$	51,736	$	55,195
	Accounts receivable less allowance for uncollectible accounts:
	2012 - $1,236; 2011 - $1,399			112,925		121,863
	Materials, supplies and fuel, at average cost			70,065		57,134
	Intercompany income taxes receivable			10,351		10,351
	Deferred income taxes			42,464		32,311
	Other current assets			14,019		7,504
Total Current Assets				301,560		284,358

Utility Property:
	Plant in service			3,678,045		3,577,946
	Construction work-in-progress			139,276		134,886
		Total		3,817,321		3,712,832
	Less accumulated provision for depreciation			1,309,962		1,277,454
		Total Utility Property, Net		2,507,359		2,435,378

Investments and other property, net				6,438		5,901

Deferred Charges and Other Assets:
	Regulatory assets			300,813		333,138
	Regulatory asset for pension plans			100,270		104,159
	Other deferred charges and assets			13,440		21,074
Total Deferred Charges and Other Assets				414,523		458,371

TOTAL ASSETS			$	3,229,880	$	3,184,008


(Continued)

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

		September 30,		December 31,
		2012		2011
LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities:
	Current maturities of long-term debt (Note 4)	$	250,094	$	-
	Accounts payable		83,714		99,897
	Accounts payable, affiliated companies		27,807		27,788
	Accrued expenses		29,137		32,840
	Deferred energy (Note 3)		73,998		85,365
	Other current liabilities		14,040		14,846
Total Current Liabilities			478,790		260,736

Long-term debt (Note 4)			928,282		1,179,326

Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
	Deferred income taxes		449,708		398,787
	Deferred investment tax credit		9,133		10,042
	Accrued retirement benefits		55,819		74,297
	Regulatory liabilities		223,830		211,308
	Other deferred credits and liabilities		63,899		74,970
Total Deferred Credits and Other Liabilities			802,389		769,404

Total Shareholder's Equity
	Common stock, $3.75 par value; 20,000,000 shares authorized
	1,000 shares issued and outstanding for 2012 and 2011		4		4
	Other paid-in capital		1,111,262		1,111,262
	Retained deficit		(89,590)		(135,340)
	Accumulated other comprehensive loss		(1,257)		(1,384)
Total Shareholder's Equity			1,020,419		974,542

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	3,229,880	$	3,184,008

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


(Concluded)

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Nine Months Ended
			September 30,
			2012		2011
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	65,750	$	45,424
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		80,594		79,647
		Deferred taxes and deferred investment tax credit		42,809		23,296
		AFUDC-equity		(1,843)		(1,875)
		Deferred energy		(11,367)		(35,453)
		Amortization of other regulatory assets		58,484		59,855
		Other, net		(15,532)		8,546
	Changes in certain assets and liabilities:
		Accounts receivable		13,452		13,917
		Materials, supplies and fuel		(12,915)		(17,190)
		Other current assets		(6,512)		(964)
		Accounts payable		(21,002)		12,833
		Accrued retirement benefits		(18,477)		(4,504)
		Other current liabilities		(3,522)		(6,447)
		Other deferred assets		(1,160)		(1,194)
		Other regulatory assets		(15,588)		(28,097)
		Other deferred liabilities		(6,282)		(2,501)
Net Cash from Operating Activities				146,889		145,293

CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(155,182)		(102,773)
		Proceeds from sale of asset		-		134,606
		Customer advances for construction		(2,221)		(4,994)
		Contributions in aid of construction		29,590		14,726
		Investments and other property - net		24		15
Net Cash from (used by) Investing Activities				(127,789)		41,580

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		(1,447)		-
		Retirement of long-term debt		(1,112)		(16,114)
		Dividends paid		(20,000)		(114,000)
Net Cash used by Financing Activities				(22,559)		(130,114)

Net Increase (Decrease) in Cash and Cash Equivalents				(3,459)		56,759
Beginning Balance in Cash and Cash Equivalents				55,195		9,552
Ending Balance in Cash and Cash Equivalents			$	51,736	$	66,311

Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	45,772	$	45,632
	Significant non-cash transactions:
		Accrued construction expenses as of September 30,	$	21,060	$	17,465
The accompanying notes are an integral part of the financial statements.

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ 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		Deficit		Income (Loss)		Equity
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


December 31, 2011		1,000	$	4	$	1,111,262	$	(135,340)	$	(1,384)	$	974,542
	Net Income	-		-		-		65,750		-		65,750
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(68))	-		-		-		-		127		127
	Dividends Declared	-		-		-		(20,000)		-		(20,000)
September 30, 2012		1,000	$	4	$	1,111,262	$	(89,590)	$	(1,257)	$	1,020,419

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., 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 2011 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the nine months ended September 30, 2012, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

Certain financial statement line items for prior periods have been reclassified to conform with current year presentation. The reclassifications have not affected previously reported reports of operations, statements of financial position or shareholders’ equity.

Accounting Policies

Consolidations of VIEs

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 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, 2012, 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.

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 purchases and normal 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 purchases 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. As a result of the suspension of the Utilities’ commodity hedging program, derivative transactions were immaterial for the period ended September 30, 2012.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments, 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 and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities. Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements in 2011 Form 10-K). Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any under/over collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

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, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,026,488	$	4	$	802,334	$	224,150	$	212,073	$	12,077

Energy Costs:
	Fuel for power generation		171,316		-		123,992		47,324		47,324		-
	Purchased power		205,686		-		171,687		33,999		33,999		-
	Gas purchased for resale		5,382		-		-		5,382		-		5,382
	Deferred energy		(29,036)		-		(22,685)		(6,351)		(5,498)		(853)
Energy efficiency program costs			32,584		-		28,492		4,092		4,092		-
Total Costs		$	385,932	$	-	$	301,486	$	84,446	$	79,917	$	4,529

Gross Margin		$	640,556	$	4	$	500,848	$	139,704	$	132,156	$	7,548

Other operating expenses			100,108		608		65,372		34,128
Maintenance			19,014		-		12,533		6,481
Depreciation and amortization			94,512		-		66,975		27,537
Taxes other than income			15,682		45		9,743		5,894

Operating Income (Loss)		$	411,240	$	(649)	$	346,225	$	65,664

Nine Months Ended
September 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	2,378,606	$	12	$	1,751,165	$	627,429	$	549,886	$	77,543

Energy Costs:
	Fuel for power generation		400,936		-		285,799		115,137		115,137		-
	Purchased power		486,894		-		388,494		98,400		98,400		-
	Gas purchased for resale		46,491		-		-		46,491		-		46,491
	Deferred energy		(30,285)		-		(15,461)		(14,824)		(13,854)		(970)
Energy efficiency program costs			76,609		-		65,466		11,143		11,143		-
Total Costs		$	980,645	$	-	$	724,298	$	256,347	$	210,826	$	45,521

Gross Margin		$	1,397,961	$	12	$	1,026,867	$	371,082	$	339,060	$	32,022

Other operating expenses			307,080		2,382		200,484		104,214
Maintenance			76,190		-		52,594		23,596
Depreciation and amortization			281,690		-		201,096		80,594
Taxes other than income			44,457		282		26,793		17,382

Operating Income (Loss)		$	688,544	$	(2,652)	$	545,900	$	145,296

Three Months Ended
September 30, 2011			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	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)
Energy efficiency program costs			23,047		-		20,451		2,596		2,596		-
Total Costs		$	439,691	$	-	$	354,806	$	84,885	$	75,919	$	8,966

Gross Margin		$	578,105	$	4	$	444,108	$	133,993	$	126,344	$	7,649

Other operating expenses			104,598		661		68,004		35,933
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

Nine Months Ended
September 30, 2011			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	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
Energy efficiency program costs			23,047		-		20,451		2,596		2,596		-
Total Costs		$	1,105,714	$	-	$	797,674	$	308,040	$	216,767	$	91,273

Gross Margin		$	1,227,996	$	11	$	865,206	$	362,779	$	328,695	$	34,084

Other operating expenses			308,119		2,243		195,040		110,836
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

NOTE 3. REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 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, 2012 (dollars in thousands):

		September 30, 2012
		NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Nevada Deferred Energy
	Cumulative Deferred Balance authorized in 2012 DEAA	$	(262,845)	$	(177,336)	$	(56,422)	$	(29,087)
	2012 Amortization		233,659		148,747		65,038		19,874
	2012 Deferred Energy Over Collections ⁽¹⁾		(199,905)		(126,504)		(53,440)		(19,961)
Nevada Deferred Energy Balance at September 30, 2012 - Subtotal		$	(229,091)	$	(155,093)	$	(44,824)	$	(29,174)
Reinstatement of deferred energy (effective 6/07, 10 years)			105,154		105,154		-		-
	Total Deferred Energy	$	(123,937)	$	(49,939)	$	(44,824)	$	(29,174)

Deferred Assets
	Deferred energy	$	90,244	$	90,244	$	-	$	-
Current Liabilities
	Deferred energy		(214,181)		(140,183)		(44,824)		(29,174)
	Total Net Deferred Energy	$	(123,937)	$	(49,939)	$	(44,824)	$	(29,174)

⁽¹⁾	These deferred energy over collections are subject to quarterly rate resets as discussed in Note 3, Regulatory Actions, of the Notes to
	Financial Statements in the 2011 Form 10-K.

Nevada Power Company

NPC 2012 DEAA, TRED and REPR, Rate Filings

In March 2012, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011, to reset the TRED and REPR rate elements and to retire the unamortized balance of NPC’s 2008 GRC deferred rate increase, as discussed in Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K. In September 2012, the PUCN issued its final order which resulted in an overall increase in revenue requirement of approximately

$37.7 million for the 2008 GRC deferred rate increase, REPR and TRED effective October 2012. Included in its September order are immaterial adjustments to deferred fuel and purchase power balances and a requirement to increase the REPR rate to include prospective customer incentives associated primarily with its solar rebate programs.

NPC 2012 EEIR, EEPR Rate Filings

Subsequent to filing NPC’s DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in NPC’s Annual Demand Side Management Update Report, requiring NPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications. As a result, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow NPC to amend the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components. In July 2012, NPC filed an amended EEIR and EEPR rate request and upon final hearing (currently scheduled in early November 2012), and approval of the amendments by the PUCN, rates for the EEIR and EEPR components would become effective January 2013.

The September PUCN approval of the 2012 DEAA, TRED and REPR application and the July 2012 EEIR and EEPR amendment include the following (dollars in millions):

				Authorized/
				Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	2008 GRC Deferred Rate Increase⁽¹⁾		Oct. 2012	$	11.5	$	-	$	11.5
	REPR⁽²⁾		Oct. 2012		37.4		8.5		28.9
	TRED⁽²⁾		Oct. 2012		15.3		18.0		(2.7)
	EEPR Base⁽²⁾		Jan. 2013		33.1		57.3		(24.2)
	EEPR Amortization⁽²⁾		Jan. 2013		8.9		21.2		(12.3)
	EEIR Base		Jan. 2013		11.0		16.8		(5.8)
	EEIR Amortization		Jan. 2013		10.4		4.8		5.6
		Total Revenue Requirement		$	127.6	$	126.6	$	1.0

⁽¹⁾	This rate request represents revenues previously recorded as a result of NPC's 2008 GRC. As such, NPC will not record further
	revenue related to this rate component, but will collect such amounts from its customers. Reference Note 3,
	Regulatory Actions, NPC 2008 GRC, of the Notes to Financial Statements in the 2011 Form 10-K.
⁽²⁾	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected.
	As a result, such programs have no effect on Operating or Net Income.

NPC Petition for Declaratory Order and Accounting Guidance - Telecommunication Tower Sale

In March 2012, NPC filed a petition with the PUCN to obtain a declaratory order and the accounting guidance necessary to establish a regulatory account for the gain on sale of NPC’s telecommunication towers to Global Tower Partners, LLC in August 2011 as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements of the 2011 Form 10-K. In July 2012, the PUCN approved a stipulation between NPC, the Bureau of Consumer Protection, and PUCN staff that provides for an allocation of $27.3 million of the approximate $32.0 million gain on sale to the ratepayers. The amortization of the gain will coincide with the rate effective date of NPC’s next GRC, which is mandated in 2015. In the quarter ended September 30, 2012, NPC recorded approximately $5.5 million, including an adjustment to previously recorded carrying charges to other income for the remaining balance of the gain on sale.

Sierra Pacific Power Company

SPPC 2012 Electric DEAA, TRED and REPR Rate Filings

In March 2012, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011 and to reset the TRED and REPR rate elements. In September 2012, the PUCN issued its final order which resulted in an overall increase in revenue requirement of $1.7 million for the REPR and TRED effective October 2012. Included in its September order are immaterial adjustments to deferred fuel and purchase power balances and a requirement to increase the REPR rate to include prospective customer incentives associated primarily with its solar rebate programs.

SPPC 2012 EEIR, EEPR Rate Filings

Subsequent to filing SPPC’s DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in SPPC’s Annual Demand Side Management Update Report, requiring SPPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications. As a result, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow SPPC to amend the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components. In July 2012, SPPC filed an amended EEIR and EEPR rate request and upon final hearing (currently scheduled in early November 2012) and approval of the amendments by the PUCN, rates for the EEIR and EEPR components would become effective January 2013.

The September PUCN approval of the 2012 DEAA, TRED and REPR application and the July 2012 EEIR and EEPR amendment include the following (dollars in millions):

				Authorized/
				Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR⁽¹⁾		Oct. 2012	$	43.3	$	38.5	$	4.8
	TRED⁽¹⁾		Oct. 2012		6.1		9.2		(3.1)
	EEPR Base⁽¹⁾		Jan. 2013		5.4		9.8		(4.4)
	EEPR Amortization⁽¹⁾		Jan. 2013		1.7		4.7		(3.0)
	EEIR Base		Jan. 2013		4.9		3.1		1.8
	EEIR Amortization		Jan. 2013		1.9		0.5		1.4
		Total Revenue Requirement		$	63.3	$	65.8	$	(2.5)

⁽¹⁾	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues
	collected. As a result, such programs have no effect on Operating or Net Income.

SPPC 2012 Nevada Gas DEAA

In March 2012, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ending December 31, 2011 and to reset the REPR. In September 2012, the PUCN issued its final order which result in an overall increase of $0.2 million.

FERC Matters

Nevada Power Company

NPC 2012 FERC Transmission Rate Case

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003. The rate changes requested in this filing would result in an overall annual revenue increase of $11.3 million. The requested rate effective date is January 1, 2013, which is subject to final approval by the FERC in 2013.

Sierra Pacific Power Company

SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003 respectively. The rate changes requested in this filing would result in an overall annual revenue increase of $3.2 million. The requested rate effective date is January 1, 2013, which is subject to final approval by the FERC in 2013.

NOTE 4. LONG-TERM DEBT

Maturities of Long-Term Debt

As of September 30, 2012, NVE’s, NPC’s and SPPC’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
2012 ⁽¹⁾			$	(371)	$	-	$	(400)	$	29
2013				256,585		-		6,517		250,068
2014				324,153		195,000		129,142		11
2015				251,579		-		251,567		12
2016				661,682		-		211,677		450,005
	Total Debt 2012-2016			1,493,628		195,000		598,503		700,125
Thereafter				3,529,214		315,000		2,747,784		466,430
	Total Debt Before Unamortized Premium (Discount)			5,022,842		510,000		3,346,287		1,166,555
Unamortized Premium (Discount) Amount				1,745		-		(10,076)		11,821
	Total Debt		$	5,024,587	$	510,000	$	3,336,211	$	1,178,376

⁽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.

Nevada Power Company

$500 Million Revolving Credit Facility

In March 2012, NPC terminated its $600 million secured revolving credit facility (which would have expired in April 2013) and replaced it with a $500 million revolving credit facility, maturing in March 2017 and secured by NPC’s General and Refunding Mortgage Bond, Series Z, in an aggregate principal amount of $500 million (the “NPC Credit Agreement”). The administrative agent for the NPC Credit Agreement remains Wells Fargo Bank, National Association. NPC may use the facility for general corporate purposes and for the issuance of letters of credit.

The rate for outstanding loans under the NPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s secured debt credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 0.50% and the LIBOR rate margin is 1.50%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

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 1.00. In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE. As of September 30, 2012, NPC was in compliance with this covenant requirement. 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.

The NPC Credit Agreement provides for an event of default if there is a failure under NPC's other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.

Similar to the $600 million secured revolving credit facility that it replaced, the NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The NPC Credit Agreement 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 in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities' commodity hedging program, there was no negative mark-to-market exposure for NPC as of November 6, 2012 that would impact borrowings.

Maturity of General and Refunding Mortgage Notes, Series I

Sierra Pacific Power Company

$250 Million Revolving Credit Facility

In March 2012, SPPC terminated its $250 million secured revolving credit facility (which would have expired in April 2013) and replaced it with a $250 million revolving credit facility, maturing in March 2017 and secured by SPPC’s General and Refunding Mortgage Bond, Series S, in an aggregate principal amount of $250 million (the “SPPC Credit Agreement”). The administrative agent for the SPPC Credit Agreement is Wells Fargo Bank, National Association. SPPC may use the facility for general corporate purposes and for the issuance of letters of credit.

The rate for outstanding loans under the SPPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon SPPC’s secured debt credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 0.50% and the LIBOR rate margin is 1.50%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

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 1.00. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. As of September 30, 2012, SPPC was in compliance with this covenant requirement. 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.

The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC's other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.

Similar to the $250 million secured revolving credit facility that it replaced, the SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The SPPC Credit Agreement contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the reduction in availability under the revolving credit facility to SPPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities'

commodity hedging program, there was no negative mark-to-market exposure for SPPC as of November 6, 2012 that would impact borrowings.

NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The September 30, 2012 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. As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2011 Form 10-K, investments held in Rabbi Trust and cash surrender value of life insurance policies continue to be considered Level 1 and Level 2, respectively, in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at September 30, 2012, 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 $6.0 billion as of December 31, 2011.

The total fair value of NPC’s consolidated long-term debt at September 30, 2012, 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 $4.1 billion at December 31, 2011.

The total fair value of SPPC’s consolidated long-term debt at September 30, 2012, 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, 2011.

NOTE 6. 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 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,
		2012		2011		2012		2011
Service cost	$	4,406	$	4,607	$	595	$	653
Interest cost		10,228		10,169		1,905		2,090
Expected return on plan assets		(12,447)		(12,192)		(1,563)		(1,596)
Amortization of prior service cost		(724)		(738)		(987)		(987)
Amortization of net loss		3,473		4,155		731		1,083
Net periodic benefit cost	$	4,936	$	6,001	$	681	$	1,243


	Pension Benefits				Other Postretirement Benefits
	For the Nine Months Ended September 30,				For the Nine Months Ended September 30,
		2012		2011		2012		2011
Service cost	$	13,220	$	13,820	$	1,787	$	1,958
Interest cost		30,684		30,507		5,715		6,270
Expected return on plan assets		(37,341)		(36,575)		(4,690)		(4,789)
Amortization of prior service cost		(2,173)		(2,214)		(2,961)		(2,961)
Amortization of net loss		10,418		12,465		2,193		3,250
Net periodic benefit cost	$	14,808	$	18,003	$	2,044	$	3,728

The average percentage of NVE net periodic costs capitalized during 2012 and 2011 was 34.97% and 33.26%, respectively.

NPC

	Pension Benefits				Other Postretirement Benefits
		For the Three Months Ended September 30,				For the Three Months Ended September 30,
		2012		2011		2012		2011
Service cost	$	2,358	$	2,445	$	350	$	363
Interest cost		4,881		4,880		602		615
Expected return on plan assets		(6,237)		(6,169)		(592)		(590)
Amortization of prior service cost		(456)		(470)		229		229
Amortization of net loss		1,363		1,690		221		302
Net periodic benefit cost	$	1,909	$	2,376	$	810	$	919


	Pension Benefits				Other Postretirement Benefits
		For the Nine Months Ended September 30,				For the Nine Months Ended September 30,
		2012		2011		2012		2011
Service cost	$	7,072	$	7,336	$	1,050	$	1,090
Interest cost		14,643		14,640		1,807		1,844
Expected return on plan assets		(18,711)		(18,508)		(1,775)		(1,769)
Amortization of prior service cost		(1,367)		(1,409)		687		687
Amortization of net loss		4,089		5,069		662		906
Net periodic benefit cost	$	5,726	$	7,128	$	2,431	$	2,758

The average percentage of NPC net periodic costs capitalized during 2012 and 2011 was 36.92% and 37.18%, respectively.

SPPC

	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended September 30,				For the Three Months Ended September 30,
	2012		2011		2012		2011
Service cost	$	1,695	$	1,840	$	227	$	271
Interest cost		5,043		5,013		1,283		1,457
Expected return on plan assets		(5,937)		(5,741)		(941)		(976)
Amortization of prior service cost		(277)		(277)		(1,220)		(1,219)
Amortization of net loss		2,026		2,412		504		773
Net periodic benefit cost	$	2,550	$	3,247	$	(147)	$	306


	Pension Benefits				Other Postretirement Benefits
	For the Nine Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
Service cost	$	5,086	$	5,520	$	682	$	815
Interest cost		15,130		15,038		3,848		4,372
Expected return on plan assets		(17,813)		(17,223)		(2,823)		(2,929)
Amortization of prior service cost		(831)		(831)		(3,658)		(3,658)
Amortization of net loss		6,078		7,235		1,511		2,319
Net periodic benefit cost	$	7,650	$	9,739	$	(440)	$	919

The average percentage of SPPC net periodic costs capitalized during 2012 and 2011 was 35.09% and 31.22%, respectively.

In 2012, NVE offered a voluntary lump sum pension payout to former employees not currently of retirement age but eligible for future benefits under NVE’s pension plan in an effort to reduce NVE’s future pension benefit obligation. As a result, NVE paid approximately $7.3 million as of September 30, 2012 from pension assets. NVE expects to payout an additional lump sum of approximately $11.9 million from the pension assets during the fourth quarter of 2012.

During the nine months ended September 30, 2012 and 2011, the company made contributions to the pension plan totaling $15.0 million and $10.0 million, respectively, and $7.1 million and $0 million, respectively, in 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 2012 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 2012 assumptions funding levels similar to the 2011 funding. The amounts to be contributed in 2012 may change subject to market conditions.

NOTE 7. COMMITMENTS AND CONTINGENCIES

Environmental

NPC

NEICO

NEICO, a wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.

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. Responses were provided back to the EPA in February 2012 and NPC will continue to monitor developments relating to this Section 114 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, 2012, environmental expenditures did not change materially from those disclosed in the 2011 Form 10-K; however, in August 2012, the EPA issued a final Regional Haze Rule which may impact NVE and the Utilities as described below.

Regional Haze Rules

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. However, in March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station. In that March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date. In

August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP. For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule. NVE continues to work toward finalizing the retrofit designs for the affected BART units. Depending on certain regulatory approvals, NVE expects to retire Tracy Generating Station Units 1 and 2, install retrofit controls on Tracy Generating Station Unit 3, Ft. Churchill Generating Station Units 1 and 2, and install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3. Compliance with the Regional Haze Rules are estimated to cost approximately $80 million over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club, and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE intends to intervene in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned.

The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules and is currently awaiting an EPA BART determination, which is expected for proposal prior to the end of 2012.

Litigation Contingencies

NPC

Peabody Western Coal Company – Royalty Claim

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and 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 June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”). NPC was 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 asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process. The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit. In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible refiling.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement among the Navajo Nation, Peabody, Salt River and SCE. At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station.

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station. NPC has not agreed to contribute to SCE’s portion of the DC Lawsuit settlement.

Management is currently negotiating a settlement with SCE, but does not believe the impact of any such settlement 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 rebuild, 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 Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company (collectively, the "Insurers") for the Farad Dam. In 2003, SPPC initiated federal court litigation against the insurers of the failed unit, who contested the extent and amount of insurance coverage. Coverage has been established through this litigation, but the matter was pending before the Ninth Circuit Court of Appeals (Ninth Circuit) for determination of the amount of coverage which could range from approximately $1.3 million to the estimated cost to rebuild the diversion dam, which is estimated to be approximately $20 million. On July 27, 2012, the Ninth Circuit entered its Order and reversed the valuation holding of the District Court. The Ninth Circuit set the value of Farad Dam at $19.8 million with some deduction for depreciation to be determined upon remand to the District Court. The court also affirmed SPPC’s right to recover the $4.0 million in permitting and design costs, which is part of the $19.8 million replacement cost. Finally, the court affirmed full replacement cost in the event of a rebuild, and further finds that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.

It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC as a whole.

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 Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. 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. 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, as of September 30, 2012, capitalized construction costs associated with GBT’s 75% interest of $241.1 and $12.7 million at NPC and SPPC, respectively, were included in CWIP with a corresponding credit to other deferred liabilities.

NOTE 8. 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,
			2012		2011		2012		2011
Basic EPS
	Numerator ($000)
		Net Income	$	223,170	$	173,462	$	304,782	$	188,680

	Denominator
		Weighted average number of common shares outstanding		235,961,402		235,990,373		235,986,874		235,796,321

	Per Share Amounts
		Net Income per share - basic	$	0.95	$	0.74	$	1.29	$	0.80

Diluted EPS
	Numerator ($000)
		Net Income	$	223,170	$	173,462	$	304,782	$	188,680

	Denominator⁽¹⁾
		Weighted average number of shares outstanding before dilution		235,961,402		235,990,373		235,986,874		235,796,321
		Stock options		39,256		33,343		37,592		36,314
		Non-Employee Director stock plan		166,829		141,122		160,257		142,587
		Employee stock purchase plan		6,742		4,012		6,785		4,547
		Restricted Shares		584,750		146,464		533,750		123,940
		Performance Shares		1,362,753		1,586,016		1,125,272		1,217,087
	Diluted Weighted Average Number of Shares			238,121,732		237,901,330		237,850,530		237,320,796

	Per Share Amounts
		Net income per share - diluted	$	0.94	$	0.73	$	1.28	$	0.80

	⁽¹⁾	The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices higher than market prices for all periods. If the conditions for conversion were met under this plan, 327,503 and 329,382 shares would be included for the three and nine months ended September 30, 2012, respectively, and 409,080 would be included for both the three and nine months ended September 30, 2011.

NOTE 9. COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

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

Declaration Date		Amount	Payable Date	Shareholders of Record Date

February 10, 2012	$	0.13	March 21, 2012	March 6, 2012
May 7, 2012	$	0.17	June 20, 2012	June 5, 2012
August 2, 2012	$	0.17	September 19, 2012	September 4, 2012
November 7, 2012	$	0.17	December 19, 2012	December 4, 2012

On November 7, 2012, NPC declared a dividend to NVE of $65 million. For the nine months ended September 30, 2012, NPC and SPPC paid dividends to NVE of $119 million and $20 million, respectively.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program. All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award. Treasury stock is accounted for using the cost method. During the nine months ended September 30, 2012, NVE repurchased 252,000 shares of common stock for approximately $4.5 million.

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, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, 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, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)

construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(4)

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 the Utilities existing operations as well as our construction program;

(5)

security breaches of our information technology or supervising control and data systems, or the systems of others upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information;

(6)

unfavorable rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, or with FERC, including, 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, renewable energy and energy efficiency recovery programs;

(7)

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

(8)

employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, the ability to adjust the labor cost structure to changes in growth within our service territories;

(9)

whether the Utilities’ newly installed advanced metering system will integrate with other computer information systems, perform as expected, and in all other respects, meet operational, commercial and regulatory requirements;

(10)

the effect of existing or future Nevada, or federal laws or regulations affecting the electric industry, including those 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;

(11)

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

(12)

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;

(13)

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;

(14)

explosions, fires, accidents and mechanical breakdowns that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, 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;

(15)

the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;

(16)

the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets as a result of the viability of European sovereign debt or other problems, 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;

(17)

whether NVE's BOD will 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 contained in NVE's and the Utilities' agreements;

(18)

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;

(19)

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

(20)

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 the Utilities’ services, including the effect on the Nevada gaming industry from the opening of additional gaming establishments in other states and internationally;

(21)

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;

(22)

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;

(23)

changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends;

(24)

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; and

(25)

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 that are specific 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 such agreements 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 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.

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.

For the three months ended September 30, 2012, NVE recognized net income of $223.2 million, compared to $173.5 million for the same period in 2011. The increase in net income is primarily due to an increase in gross margin of $62.5 million (pre-tax) as a result of an increase in BTGR rates at NPC, effective January 1, 2012, an increase in usage by certain industrial customers, slight growth in the number of customers and to a lesser extent weather. See the Utilities’ respective Results of Operations, for further discussion of gross margin. Also contributing to the increase in net income was a $6.2 million (pre-tax) decrease in interest expense, excluding AFUDC-debt, an increase in other income primarily due to a $5.5 million (pre-tax) gain on sale of telecommunication towers recorded in 2012 (reference Note 3, Regulatory Actions, in the Condensed Notes to Financial Statements in Form 10-K) and $1.4 million (pre-tax) gains on investments in 2012, as well as, a $3.5 million (pre-tax) loss on investments recorded in 2011. Offsetting the increase in net income was the absence of an $8 million reduction in maintenance expense recorded in 2011 as a result of the final calculation of a termination amount for a long term service agreement for the Higgins Generating Station which was previously expensed in 2010.

For the nine months ended September 30, 2012, NVE recognized net income of $304.8 million compared to $188.7 million for the same period in 2011. The increase in net income, similar to the three month period, is primarily due to an increase in gross margin of $170.0 million (pre-tax); however, in the case of usage, weather had a greater impact particularly during the second quarter of 2012. Also contributing to the increase from the prior period was a $17.4 million (pre-tax) decrease in interest expense, excluding AFUDC-debt, and a $5.8 million (pre-tax) adjustment recorded in the second quarter of 2011, as a result of an order from the PUCN adjusting EEIR revenue recorded in 2010. For further discussion of the EEIR adjustment, see Note 3, Regulatory Actions, EEIR, of the Notes to Financial Statements in the 2011 Form 10-K. Further contributing to the increase in net income was a $5.5 million (pre-tax) gain on sale of telecommunication towers recorded in 2012 (reference Note 3, Regulatory Actions, in the Condensed Notes to Financial Statements in Form 10-K), $2.3 million (pre-tax) gains on investments in 2012, as well as, a $2.8 million (pre-tax) loss on investments recorded in 2011, and a $4.9 million (pre-tax) construction contract settlement related to the Harry Allen Generating Station. These increases were partially offset by an increase in depreciation expense of $15.2 million (pre-tax) and a reduction in AFUDC (debt and equity) of $11.1 million (pre-tax), primarily due to the completion of the Harry Allen Generating Station in May 2011. Further offsetting the increase in net income was the absence of an $8 million reduction in maintenance expense recorded in 2011 as a result of the final calculation of a termination amount for a long term service agreement for the Higgins Generating Station which was previously expensed in 2010.

The Utilities are regulated by the FERC and 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. The PUCN has authority over rates charged to retail customers, the issuance of securities by the Utilities and transactions with affiliated parties. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically

occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the 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.

Future Challenges

For the remainder of 2012 NVE and the Utilities must continue to balance the needs of our customers and regulatory requirements while still providing value to our shareholders. As customer growth and demand have stabilized, the Utilities are transitioning from an emphasis on capital investment to an emphasis on optimizing our assets and resources. The Utilities believe they are entering a period of decreasing need for rate relief, more stable earnings, improving returns and sustained free cash flow. We expect that this transition will allow NVE to build shareholder value through a combination of increasing its common stock dividend payout ratio, strengthening its capital structure and considering new investment opportunities. On May 7, 2012, the BOD approved a dividend policy, subject to its consideration of factors ordinarily affecting dividend policy, the objective of which is to achieve a dividend payout ratio of 55% to 65%. However, the accomplishment of such target may be over a period of time, which management is unable to predict at this time, and may be affected by certain challenges including, but not limited to:

	•	Economic conditions in Nevada;
	•	Executing the Evolution of Energy Strategy; and
	•	Managing our regulatory environment.

Economic Conditions

Leading economic indicators for Nevada suggest that improvements in economic conditions will be very slow. Although the unemployment rate in Nevada remains above the national average, it has improved over the past year.

Economic conditions in Nevada have a significant influence on NVE’s business decisions as we consider various interrelated factors including:

	•	customer growth;
	•	customer usage;
	•	load factors;
	•	managing operating and maintenance expenses within projected revenue without compromising safety, reliability and efficiency;
	•	pressure on regulators to limit necessary rate increases or otherwise lessen rate impacts upon customers;
	•	collections on accounts receivable; and
	•	future capital projects and capital requirements.

Executing the Evolution of Energy Strategy

As discussed in their 2011 Form 10-K, NVE and the Utilities have transitioned from their three-part energy strategy to the Evolution of Energy Strategy outlined below, with less emphasis on capital investment to more emphasis on optimizing our assets and resources.

Evolution of Energy Strategy:

	•	Empower customers through more focused energy efficiency programs
	•	Pursue cost-effective renewable energy initiatives
	•	Optimize generation efficiency and transmission facilities
	•	Engage employees to improve processes, reduce costs, and enhance performance

Empower customers through more focused energy efficiency programs

The Utilities will continue with the implementation of NV Energize, which not only provides metering and customer service operating savings, but will also provide customers with better opportunities to become more energy efficient. NVE’s traditional conservation and energy efficiency programs, which have focused on behavioral change and technology replacement, will be

enhanced by the new features enabled by NV Energize. Specifically, customers will have access to better information to help them manage their energy usage and select from enhanced energy efficiency options, including demand response and pricing programs. Through September 30, 2012, NVE has installed approximately 1.1 million Smart Meters in Nevada. NVE expected to have approximately 1.4 million meters installed statewide by the end of 2012; however, as alternative metering options are currently under consideration by the PUCN and not expected for final decision until sometime during the fourth quarter, NVE now anticipates the completion of the meter deployment to be in early 2013. The NV Energize capabilities will allow NVE to help customers implement the most cost-effective mix of energy efficiency and conservation options that will also qualify toward fulfillment of the Portfolio Standard.

Pursue cost-effective renewable energy initiatives

NVE must strive to effectively 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. In 2011, Nevada’s Portfolio Standard was 15%. Both NPC and SPPC surpassed the minimum PEC requirement achieving 16.7% and 24.9%, respectively, through eligible resources in 2011. This represented the culmination of several years of developing a portfolio of diverse renewable resources throughout Nevada. While NVE is better positioned to meet the continued challenge based on recent renewable successes, NVE remains committed to incorporating clean, cost-effective renewable energy into its portfolio. As part of its continued commitment to renewable energy, NVE will continue to seek the best and most cost effective opportunities that will benefit our state, customers and environment. Depending on its needs and continuous analysis of the existing portfolio, NVE has a number of tools available to seek renewable energy values for our customers. These tools may include issuing requests for proposals for new renewable energy contracts, exploring opportunities to either jointly construct or develop projects using wind, geothermal and solar, undertaking additional short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.

The Portfolio Standard requires a specific percentage of an electric service provider’s total retail energy sales to be obtained from renewable energy resources. Renewable resources include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the portfolio percentage. In 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, to 20% in 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 satisfied from solar resources until 2016 when a minimum of 6% must be solar.

The Utilities acquire PECs through competitively-priced purchase power contracts, investments in renewable generating facilities and DSM programs. NVE seeks to meet the standard using the most cost-effective means for our customers and to pursue the best-value options that are available to the Utilities. In addition to the foregoing, this may also include economical short-term purchases of PECs (often from outside of Nevada) to fulfill projected shortfalls due to the attrition or timing of development of renewable energy projects, weather variability, regulatory/legal changes, or other supplier issues.

Optimize generation efficiency and transmission facilities

Since 2006, when NVE began its energy independence initiative, the Utilities have added approximately 3,800 MWs (nominally rated) of internal generation. NVE has the ability to obtain approximately 80% of its energy from internal generation. In 2012, NVE’s management continues to strive to optimize the Utilities’ energy portfolio in order to meet load obligations in a cost-effective and reliable manner. In addition, to the extent the Utilities have the economical opportunity to sell excess capacity or energy, they may enter into such transactions to reduce overall energy costs. NVE anticipates it will have sufficient resources to meet its forecasted load requirements for 2012. However, resource adequacy could be affected by a number of factors, including the retirement of generating stations, plant outages, the timing of commercial operation of renewable energy projects and associated purchase power agreements, customer behavior with respect to energy efficiency and conservation programs, and environmental regulations which may limit our ability to operate certain generating units.

The construction of the ON Line will enable us to optimize our transmission capabilities. 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 manage its Portfolio Standard, discussed above, and optimize its generating facilities.

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 substation on the NPC system. The Utilities own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $138 million (based on the revised costs, discussed below) will be allocated 95% and 5% to NPC and SPPC, respectively. The Utilities will have rights to 100% of the capacity of ON Line, 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 is extending from the Robinson Summit substation north to Midpoint, Idaho, and the other is commencing at the Harry Allen substation and interconnecting south to the Eldorado substation. GBT would pay for and own 100% of Phase 2 facilities. However, NPC and SPPC 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 March 2012, NVE announced that the in-service date for ON Line will be delayed due to on-going efforts to address wind-related damage sustained by some of the tower structures erected for the project. As a result, NVE is also further delaying the merger application of the Utilities. Furthermore, on June 29, 2012, NPC filed its triennial 2013 – 2032 IRP with the PUCN. The 2012 IRP includes revised cost estimates for ON Line based on an analysis of all information available to date, and provides an expected in-service date of no later than December 31, 2013. The overall ON Line construction budget has been revised from approximately $510 million to approximately $552 million before allowance for funds used during construction. The revised construction budget is based on the estimated cost of the mitigation measures identified to address the wind-induced vibration issues that have delayed the project. The Utilities have requested PUCN approval of the decision to continue with construction of ON Line with the revised in-service date and revised budget. A PUCN decision on ON Line is expected in December 2012.

Engage employees to improve processes, reduce costs, and enhance performance

The Utilities will continue to control operating, maintenance and capital costs through diligent review and process improvement initiatives by providing appropriate tools to our employees to find ways to reduce costs, improve processes, and enhance performance. This is particularly important at a time when customer growth is low. Going forward this will continue to be an over-arching theme of our energy strategy. Our goal is to maintain, reduce, or eliminate upward pressure on our customers’ prices while always delivering safe and reliable energy and assure compliance with all laws and regulations.

Managing Regulatory Environment

The Utilities’ most recent GRCs provide an opportunity to earn a 10% ROE and 10.1% ROE for NPC and SPPC, respectively. However, assets not currently included in rate base or that the Utilities are not allowed to earn a return on may impair their ability to achieve their allowed ROE. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K, for details of regulatory assets not included in rate base or not earning a return. Other items which may not earn a return are certain plant assets completed between GRC filings or that were not requested in a GRC. 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. 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. The Utilities will continue to focus on reducing regulatory lag and stabilizing cash flow by filing quarterly applications to reset the BTER and DEAA rates. Furthermore, the Utilities file annual EEIR and EEPR base rate and amortization applications in an effort to recover these amounts in a timely manner.

2012 Goals

Management cannot predict the pace economic recovery may occur in Nevada, but expects that the Nevada economy will gradually recover over the next several years. As such, our primary goals will focus on meeting the challenges discussed above by:

•	Effectively adjusting our business decisions based on economic conditions in Nevada;
•	Building a sustainable foundation for future requirements by executing our evolution of energy strategy:
	•	Substantial completion of the NV Energize project by the end of 2012;
	•	Empower customers through more focused energy efficiency programs;
	•	Pursue cost effective renewable energy initiatives;
	•	Continued investment in cost effective energy efficiency and conservation programs;
	•	Optimizing the use of generation facilities;
	•	Continued construction of ON Line;
	•	Engage employees to improve processes, reduce costs, enhance performance; and
•	Managing our regulatory environment.

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 $18.9 million and $24.5 million of long term debt interest costs for the nine months ended September 30, 2012 and 2011, respectively.

For the period ended September 30, 2012, NPC and SPPC paid $119 million and $20 million respectively in dividends to NVE.

On November 7, 2012, NPC declared dividends of $65 million to NVE.

Other Subsidiaries

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

Analysis of Cash Flows

NVE’s cash flows increased during the nine months ended September 30, 2012, compared to the same period in 2011, due to increased cash from operating activities, partially offset by an increase in cash used by investing and financing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to higher BTGR rates, resulting from NPC’s 2011 GRC, combined with increased customer usage. Also contributing to the increase were over collections of EEPR, reduction in spend for conservation programs, and increased customer deposits. These increases were partially offset by a change in payment terms with energy counterparties from weekly to monthly settlements in mid-2011, expiration of rates to collect the deferred rate increase from NPC’s 2008 GRC, increased funding of the retirement plan and timing of property tax payments.

Cash Used By Investing Activities. The increase in cash used by investing activities was primarily due to the receipt of proceeds from the sale of California Assets and the telecommunication towers in 2011, an increase in the construction of ON Line and NV Energize, partially offset by a decrease in the use of cash as a result of a decrease in construction activity primarily for the Harry Allen Generating Station expansion completed in May 2011.

Cash Used By Financing Activities. Cash used by financing activities increased due to the reduction in cash from issuance of debt, higher dividend payments, the settlement of equity compensation through open market purchases of common stock, and the

repurchase of common stock which may be reissued to satisfy future equity compensation costs as referenced in Note 9, Common Stock and Other Paid-In Capital, of the Condensed Notes to Financial Statements. These increases were partially offset by a decrease in debt retirements.

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. Another significant use of cash is the refunding of previously over-collected amounts from customers; however, this is partially mitigated as the Utilities continue to over-collect from customers as a result of current rates set above the current cost of fuel and purchased power. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions. Available liquidity as of September 30, 2012 was as follows (in millions):

Available Liquidity as of September 30, 2012 (in millions)
			NVE		NPC		SPPC
Cash and Cash Equivalents			$	25.2	$	124.5	$	51.7
	Balance available on Revolving Credit Facilities⁽¹⁾			N/A		497.3		239.5
				25.2		621.8		291.2

⁽¹⁾		As of November 6, 2012, NPC and SPPC had approximately $497.3 million and $243.7 million available under their
		revolving credit facilities, which includes reductions in availability for letters of credit, as discussed further under NPC's and
		SPPC's Financing Transactions.

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 has no debt maturities in either 2012 or 2013. In April 2012, NPC used $120 million from its revolving credit facility along with $10 million from cash on hand to pay for the maturity of its 6.5% General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million. NPC does not have any other debt maturities in 2012; however, 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 2013. SPPC has no debt maturities in 2012. However, SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.

In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NVE and the Utilities have transitioned to slower growth, the amount of capital expenditures has declined. NVE and the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources. As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities revolving credit facilities. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow. The free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities. To meet long term maturing debt obligations, the Utilities may 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, 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 under such circumstances, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities’ utilization of their revolving credit facilities may be limited. 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 November 6, 2012, NVE has approximately $10.8 million payable of debt service obligations remaining for 2012, which it intends to pay through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries, below). For the nine months ended, September 30, 2012, NPC and SPPC paid dividends to NVE of approximately $119 million and $20 million, respectively. On November 7, 2012, NPC declared dividends payable to NVE of $65 million.

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

During the nine months ended September 30, 2012, there were no material changes to contractual obligations as set forth in NVE’s 2011 Form 10-K.

Factors Affecting Liquidity

Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, 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 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed .70 to 1.00. Under these covenant restrictions, as of September 30, 2012, NVE (consolidated) would be allowed to incur up to $3.4 billion of additional indebtedness. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition. NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt.

Effect of Holding Company Structure

As of September 30, 2012, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: $195 million Term Loan due 2014; and $315 million of its unsecured 6.25% Senior Notes due 2020.

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, 2012, NVE, NPC, SPPC and their subsidiaries had approximately $5 billion of debt and other obligations outstanding, consisting of approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of September 30, 2012, there were no dividend restrictions imposed on the Utilities by the PUCN.

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. As of September 30, 2012, the ratings are as follows:

			Rating Agency
			Fitch⁽¹⁾	Moody’s⁽²⁾	S&P⁽³⁾
NVE		Sr. Unsecured Debt	BB	Ba1	BB+
NPC		Sr. Secured Debt	BBB*	Baa1*	BBB*
SPPC		Sr. Secured Debt	BBB*	Baa1*	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 rating outlook is positive, while Moody’s and S&P’s rating outlook is stable for NVE, NPC and SPPC.

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, 2012 for all suppliers continuing to provide power under a WSPP agreement would approximate a $56.3 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 9, Derivatives and Hedging Activities, of the Notes to Financial Statements in the 2011 Form 10-K 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 mean 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. As of September 30, 2012, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $86.4 million. Of this amount, approximately $25.9 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $60.5 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. During the second quarter of 2012, $17.9 million of letters of credit posted as collateral were returned from the counterparty to NPC during the period due to NPC’s unsecured credit rating becoming investment grade. In exchange, the amount of additional cash collateral that would be required in the event of a credit rating downgrade increased.

Financial Gas Hedges

The Utilities may 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 availability under NPC’s and SPPC’s Credit Agreement is reduced 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. As a result of the suspension of the Utilities’ commodity hedging programs, there was no negative mark-to-market exposure for NPC and SPPC as of November 1, 2012, that would impact credit availability. If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

Cross Default Provisions

None of the Utilities’ financing agreements contain 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 $195.2 million during the three months ended September 30, 2012, compared to a net income of approximately $154.6 million for the same period in 2011. During the nine months ended September 30, 2012, NPC recognized net income of approximately $256.2 million compared to a net income of approximately $161.7 million for the same period in 2011.

For the period ended September 30, 2012, NPC paid $119 million in dividends to NVE. On November 7, 2012, NPC declared a dividend of $65 million to NVE.

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

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less energy and energy efficiency program 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).

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

		Three Months Ended September 30,					Nine Months Ended September 30,
						Change from					Change from
		2012		2011		Prior Year %	2012			2011	Prior Year %
Operating Revenues:		$	802,334	$	798,914	0.4 %	$	1,751,165	$	1,662,880	5.3 %

Energy Costs:
	Fuel for power generation		123,992		162,976	(23.9)%		285,799		378,790	(24.5)%
	Purchased power		171,687		181,733	(5.5)%		388,494		399,707	(2.8)%
	Deferred energy		(22,685)		(10,354)	119.1 %		(15,461)		(1,274)	1113.6 %
Energy efficiency program costs			28,492		20,451	39.3 %		65,466		20,451	220.1 %
	Total Costs	$	301,486	$	354,806	(15.0)%	$	724,298	$	797,674	(9.2)%


Gross Margin		$	500,848	$	444,108	12.8 %	$	1,026,867	$	865,206	18.7 %

Gross margin increased $56.7 million for the three months ended September 30, 2012 compared to the same period in 2011. Approximately $48.2 million of the increase is due to an increase in BTGR rates as a result of NPC’s 2011 GRC (see Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K) and approximately $7.4 million of the increase is due to an increase in usage. Increased usage by certain industrial customers, slight growth in the number of customers and, to a lesser extent, weather contributed to the increase in usage.

Gross margin increased $161.7 million for the nine months ended September 30, 2012 compared to the same period in 2011. Similar to the discussion above for the three month period, approximately $121.0 million of the increase was due to an increase in BTGR rates and approximately $45.0 million was due to an increase in usage. Usage increased primarily due to an increase in CDDs, particularly during the second quarter of 2012, as shown in the tables below. Increased usage by certain industrial customers and slight growth in the number of customers further contributed to the increase in usage.

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):

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2. Normal is based on the average degree days for the last 20 years.

The following table shows the HDDs and CDDs within NPC’s service territory:


		Three Months Ended September 30,							Nine Months Ended September 30,
					2012 Change							2012 Change
		2012	2011	Normal	Prior Year		Normal		2012	2011	Normal	Prior Year		Normal
NPC
	Heating	-	-	-	N/A		N/A		986	1,131	1,112	(12.8)	%	(11.3)	%
	Cooling	2,313	2,312	2,209	-	%	4.7	%	3,771	3,329	3,390	13.3	%	11.2	%

Operating Revenue

			Three Months Ended September 30,					Nine Months Ended September 30,
							Change from					Change from
			2012		2011		Prior Year %	2012		2011		Prior Year %
Operating Revenues:
	Residential		$	436,534	$	426,827	2.3 %	$	915,953	$	824,378	11.1 %
	Commercial			121,334		118,599	2.3 %		318,126		304,911	4.3 %
	Industrial			227,824		236,452	(3.6)%		473,548		485,347	(2.4)%
		Retail revenues		785,692		781,878	0.5 %		1,707,627		1,614,636	5.8 %
	Other			16,642		17,036	(2.3)%		43,538		48,244	(9.8)%
		Total Operating Revenues	$	802,334	$	798,914	0.4 %	$	1,751,165	$	1,662,880	5.3 %

Retail sales in thousands of MWhs
		Residential		3,752		3,711	1.1 %		7,619		7,021	8.5 %
		Commercial		1,374		1,319	4.2 %		3,480		3,307	5.2 %
		Industrial		2,145		2,070	3.6 %		5,836		5,793	0.7 %
Retail sales in thousands of MWhs				7,271		7,100	2.4 %		16,935		16,121	5.0 %

Average retail revenue per MWh			$	108.06	$	110.12	(1.9)%	$	100.83	$	100.16	0.7 %

NPC’s retail revenues increased approximately $3.8 million for the three months ended September 30, 2012, as compared to the same period in 2011. The increase in BTGR rates, as a result of NPC’s GRC, contributed approximately $48.2 million to the increase in retail revenues (see Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K). Also contributing to the increase was approximately $16.6 million due to an increase in usage, primarily due to an increase in usage by certain industrial customers, slight growth in the number of customers, and to a lesser extent, weather. Further contributing to the increase was approximately $8.0 million due to the implementation of EEPR amortization rates effective October 1, 2011. These revenue increases were offset by approximately $69.9 million of rate decreases as a result of NPC’s various BTER and DEAA quarterly updates and the Deferred Energy case effective October 1, 2011. (See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K).

For the three months ended September 30, 2012, the average number of retail customers increased by 1.2%, consisting of an increase in residential and commercial customers of 1.2% and 0.9%, respectively, and a decrease in industrial customers of 0.7%, compared to the same period in the prior year.

NPC’s retail revenues increased $93.0 million for the nine months ended September 30, 2012 compared to the same period in 2011. Similar to the three month period discussed above, the increase in BTGR rates, as a result of NPC’s 2011 GRC, increased retail revenues by approximately $121 million. Also contributing to the increase in retail revenues was approximately $94.5 million from an increase in usage, primarily due to an increase in CDDs, particularly during the second quarter of 2012, as well as increased usage by certain industrial customers and slight growth in the number of customers. Further contributing to the increase was $44.7 million due to the implementation of EEPR base rates effective July 1, 2011 and EEPR amortization rates effective October 1, 2011. These revenue increases were offset by approximately $168 million of rate decreases as a result of NPC’s various BTER and DEAA quarterly updates and Deferred Energy case effective October 1, 2011. (See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K)

For the nine months ended September 30, 2012, the average number of retail customers increased by 1.3%, consisting of an increase in residential and commercial customers of 1.4% and 0.5%, respectively, and a decrease in industrial customers of 2.0%, compared to 2011.

Electric Operating Revenues – Other decreased approximately $400 thousand for the three months ended September 30, 2012, compared to the same period in 2011. The decrease is primarily due to decreases in revenue from public authorities of approximately $500 thousand and a decrease in connection fees of approximately $800 thousand, offset by increases in transmission revenue of approximately $700 thousand.

Electric Operating Revenues – Other decreased approximately $4.7 million for the nine months ended September 30, 2012 compared to the same period in 2011. The decrease is primarily due to a decrease in connection fees of approximately $2.3 million as a result of utilizing smart meters. Also contributing to the decrease was a decrease in rental income of approximately $2.1 million, as a result of the sale of the telecommunication towers by NPC in 2011.

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
		2012		2011		Prior Year %	2012		2011		Prior Year %
Energy Costs
	Fuel for power generation	$	123,992	$	162,976	(23.9)%	$	285,799	$	378,790	(24.5)%
	Purchased power		171,687		181,733	(5.5)%		388,494		399,707	(2.8)%
Energy Costs		$	295,679	$	344,709	(14.2)%	$	674,293	$	778,497	(13.4)%

MWhs
	MWhs Generated (in thousands)		5,105		4,879	4.6 %		12,264		11,138	10.1 %
	Purchased Power (in thousands)		2,392		2,520	(5.1)%		5,415		5,821	(7.0)%
Total MWhs			7,497		7,399	1.3 %		17,679		16,959	4.2 %

Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	24.29	$	33.40	(27.3)%	$	23.30	$	34.01	(31.5)%
	Average cost per MWh of Purchased Power	$	71.78	$	72.12	(0.5)%	$	71.74	$	68.67	4.5 %
	Average total cost per MWh	$	39.44	$	46.59	(15.3)%	$	38.14	$	45.90	(16.9)%

Energy Costs and the average total cost per MWh decreased for the three and nine months ended September 30, 2012, compared to the same periods in 2011, primarily due to a decrease in costs associated with lower natural gas prices. For the three months ended September 30, 2012, volume increased primarily as a result of an increase in customer usage by certain industrial customers, slight customer growth, and to a lesser extent, weather. For the nine months ended September 30, 2012, volume increased primarily due to an increase in demand as a result of an increase in CDDs, particularly during the second quarter of 2012, an increase in usage by certain industrial customers and slight customer growth.

•

Fuel for generation costs decreased $39.0 million for the three months ended September 30, 2012, while volume increased, compared to the same period in 2011. Approximately $39.6 million of the decrease was attributable to a decrease in natural gas prices. Also contributing to the decrease in costs was approximately a $2.8 million decrease in hedging activities. These decreases were partially offset by a slight increase in volume of $3.4 million due to the increase in demand as discussed above.

Fuel for generation costs decreased $93.0 million for the nine months ended September 30, 2012, while volume increased, compared to the same period in 2011. Similar to the discussion above of the three month period, approximately $94.7 million of the decrease was attributable to a decrease in natural gas prices and approximately $20.1 million of the decrease was due to a decrease in hedging activities. These decreases were partially offset by approximately $21.8 million as a result of an increase in volume due to the addition of the Harry Allen Generating Station and an increase in demand as discussed above.

•

Purchased power costs decreased $10.0 million for the three months ended September 30, 2012 compared to the same period in 2011. The decrease in purchased power costs is primarily due to approximately $23.0 million decrease in volume of non-renewable power purchased, resulting from increased self-generation, as discussed above, partially offset by a $15.9 million increase in the volume of renewable energy purchased, as mandated by the Portfolio Standard. Purchased power costs also decreased due to the decrease in the cost of non-renewable energy of approximately $4.9 million primarily driven by lower natural gas prices. The decrease in cost was partially offset by an increase in the cost of renewable power purchases of approximately $1.9 million.

Purchased power costs decreased $11.2 million for the nine months ended September 30, 2012, compared to the same period in 2011. The decrease in purchased power costs is primarily due to approximately $67.1 million decrease in volume of non-renewable power purchased, resulting from increased self-generation, as discussed above, partially offset by a $36.6 million increase in the volume of renewable energy purchased, as mandated by the Portfolio Standard. The decrease was further offset by an increase in the cost of power purchases of approximately $19.3 million primarily due to long term purchase commitments.

Deferred Energy

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %

Deferred energy	$	(22,685)	$	(10,354)	119.1 %	$	(15,461)	$	(1,274)	1113.6 %

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, 2012 and 2011 include amortization of deferred energy of $(58.3) million and $(28.0) million, respectively; and an over-collection of amounts recoverable in rates of $35.6 million and $17.7 million, respectively. Amounts for the nine months ended September 30, 2012 and 2011 include amortization of deferred energy of $(136.5) million and $(67.0) million, respectively; and an over-collection of amounts recoverable in rates of $121.0 million and $65.7 million, respectively.

Other Operating Expenses

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %

Energy efficiency program costs	$	28,492	$	20,451	39.3 %	$	65,466	$	20,451	220.1 %
Other operating expenses	$	65,372	$	68,004	(3.9)%	$	200,484	$	195,040	2.8 %
Maintenance	$	12,533	$	3,460	262.2 %	$	52,594	$	45,122	16.6 %
Depreciation and amortization	$	66,975	$	67,212	(0.4)%	$	201,096	$	186,798	7.7 %

For the three and nine months ended September 30, 2012 energy efficiency program costs increased $8.0 million and $45.0 million, respectively, compared to the prior year primarily due to the implementation of EEPR base rates in July 2011 and in the case of the nine month period, EEPR amortization rates effective October 2011.

Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 for base rates and in October 2011 for amortization rates (See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K). Costs incurred prior to the implementation of the EEPR rates are recovered through general rates and amortized to other operating expense discussed below. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income, or net income.

Other operating expenses decreased $2.6 million for the three months ended September 30, 2012, compared to the same period in 2011, primarily due to a $1.1 million decrease in stock compensation costs, $1.1 million lower pension and benefit costs, $0.9 million decrease in regulatory amortization costs, $0.9 million decrease in injuries and damages expenses and $0.7 million lower transmission and distribution expenses. The decrease was partially offset by a $3.1 million increase in amortization of energy efficiency and conservation costs.

Other operating expenses increased $5.4 million for the nine months ended September 30, 2012, compared to the same period in 2011, primarily due to $9.4 million increase in amortization of energy efficiency and conservation costs, a $2.3 million increase in stock compensation costs, and an approximate $3 million reduction in capitalized costs as a result of a decrease in construction activity. The increase was partially offset by a $3.2 million decrease in regulatory amortization costs, $1.8 million lower lease expenses, $1.5 million lower transmission and distribution costs, a $1.3 million decrease in rate case expenses and a $1.1 million decrease in customer expenses.

Maintenance expense increased $9.1 million for the three months ended September 30, 2012, compared to the same period in 2011, primarily due to the absence of an $8 million reduction in maintenance expense recorded in 2011 as a result of the final calculation of a termination amount for a long-term service agreement for the Higgins Generating Station which was previously expensed in 2010. Also contributing to the increase was $1 million of planned maintenance outages in 2012 at the Lenzie Generating Station.

Maintenance expense increased $7.5 million for the nine months ended September 30, 2012, compared to the same period in 2011, primarily due to the absence of an $8 million reduction in maintenance expense recorded in 2011 as a result of the final calculation of a termination amount for a long-term service agreement for the Higgins Generating Station which was previously expensed in 2010. Also contributing to the increase was $13 million of planned maintenance outages in 2012 at the Lenzie, Silverhawk, Harry Allen and Higgins Generating Stations. The increase was partially offset by $13.7 million planned maintenance outages in 2011 at the Reid Gardner, Navajo and Clark Generating Stations.

Depreciation and amortization did not change significantly for the three months ended September 30, 2012 compared to the same period in 2011.

Depreciation and amortization increased $14.3 million for the nine months ended September 30, 2012, compared to the same period in 2011 primarily due to increased depreciation of $8.5 million resulting from the expansion at Harry Allen Generating Station placed in service in May 2011. Also contributing to the increase was a change in depreciation rates, as of January 1, 2012, resulting from a recent depreciation study and other general plant in service increases.

Interest Expense

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012			2011	Prior Year %
Interest expense
(net of AFUDC-debt: $1,528, $842, $4,021 and $8,962)	$	51,784	$	55,267	(6.3)%	$	158,791	$	163,036	(2.6)%

Interest expense decreased $2.8 million for the three months ended September 30, 2012, compared to the same period in 2011 due to approximately $2.5 million in decreased net interest costs from various refinancings and redemptions and an approximate $700 thousand increase in AFUDC-debt primarily due to various construction projects, partially offset by variable rate debt fluctuations. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2011 Form 10-K and Note 4, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Interest expense decreased $9.2 million for the nine months ended September 30, 2012, compared to the same period in 2011. Similar to the discussion of the three month period above, the decrease is primarily due to approximately $8.6 million in decreased net interest costs from various refinancings and redemptions, partially offset by variable rate debt fluctuations. Further offsetting the decrease in interest expense was a decrease in AFUDC-debt of $4.9 million. AFUDC-debt decreased approximately $6.4 million primarily due to the completion of the Harry Allen Generating Station in May 2011, offset by an increase in AFUDC-debt of $1.3 million related to construction of ON Line. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2011 Form 10-K and Note 4, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Other Income (Expense)
	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %

Interest income (expense) on regulatory items	$	(1,623)	$	(82)	1879.3 %	$	(5,488)	$	679	(908.2)%
AFUDC-equity	$	1,833	$	1,026	78.7 %	$	4,823	$	10,979	(56.1)%
Other income	$	7,096	$	594	1094.6 %	$	14,197	$	2,708	424.3 %
Other expense	$	(2,823)	$	(7,324)	(61.5)%	$	(7,162)	$	(15,235)	(53.0)%

Interest income (expense) on regulatory items changed by approximately $1.5 million for the three months ended September 30, 2012, compared to the same period in 2011. Contributing to the change was an approximate $1.4 million net decrease of interest income due to lower regulatory asset balances, and lower over-collected deferred energy balances in 2012. Further contributing to the change was approximately $604 thousand due to a decrease in interest income related to the deferred BTGR balance, discussed in Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K.

Interest income (expense) on regulatory items changed by approximately $6.2 million for the nine months ended September 30, 2012, compared to the same period in 2011. Approximately $3.0 million of the change is due to a decrease in interest income related to the deferred BTGR balance, as discussed above. Also contributing to the change was a net $2.5 million decrease of interest income due to lower regulatory asset balances, and lower over-collected deferred energy balances in 2012.

AFUDC-equity increased for the three months ended September 30, 2012 compared to the same period in 2011 approximately $800 thousand primarily due to various construction projects.

AFUDC-equity decreased for the nine months ended September 30, 2012 compared to the same period in 2011 approximately $6.2 million. The decrease was primarily due to approximately $7.7 million decrease in AFUDC as a result of the completion of the Harry Allen Generating Station in May 2011 offset by an increase in construction of ON Line of approximately $1.6 million.

Other income increased $6.5 million for the three months ended September 30, 2012, compared to the same period in 2011, primarily due to a $5.5 million gain on the sale of telecommunication towers in 2012 and a $1.1 million gain on investments in 2012.

Other income increased $11.5 million for the nine months ended September 30, 2012, compared to the same period in 2011. The increase is primarily due to the $5.5 million gain on the sale of telecommunication towers in 2012, note above, as well as a $4.9 million Harry Allen construction project settlement in 2012 and $1.9 million of gains on investments in 2012.

The decrease in other expense of $4.5 million for the three months ended September 30, 2012, compared to the same period in 2011 is primarily due to $2.8 million loss on investments in 2011 and $2.8 million adjustments for the settlement of the deferred energy rate case in 2011, offset slightly by $1.1 million adjustment for the settlement of the deferred energy rate case in 2012. For further discussion of the DEAA adjustment, see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K and Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements.

The decrease in other expense of $8.1 million for the nine months ended September 30, 2012, compared to the same period in 2011 is primarily due to a $3.0 million adjustment, recorded in 2011, as a result on an order from the PUCN adjusting EEIR revenue recorded in 2010, $2.3 million loss on investments in 2011 and $2.8 million adjustments for the settlement of the deferred energy rate case in 2011, offset slightly by $1.1 million adjustment for the settlement of the deferred energy rate case in 2012. For further discussion of the EEIR adjustment, reference Note 3, Regulatory Actions, EEIR, of the Notes to Financial Statements in the 2011 Form 10-K. For further discussion of the DEAA adjustment see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K and Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements.

Analysis of Cash Flows

NPC’s cash flows increased during the nine months ended September 30, 2012, compared to the same period in 2011, due to an increase in cash from operating activities and a reduction in cash used by investing activities, offset partially by an increase in cash used by financing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to higher BTGR rates, resulting from NPC’s 2011 GRC, combined with increased customer usage. Also contributing to the increase were over collections of EEPR, refunds of customer deposits in 2011, and a reduction in spending for conservation programs. These increases were partially offset by quarterly BTER adjustments and negative DEAA rates to refund prior period over collected balances, expiration of rates to collect the deferred rate increase from NPC’s 2008 GRC, and timing of property tax and interest payments.

Cash Used By Investing Activities. The decrease in cash used by investing activities was primarily due to the completion of construction at the Harry Allen Generating Station in May 2011, partially offset by proceeds from the sale of certain telecommunication towers in 2011 and an increase in construction due to ON Line in 2012.

Cash Used By Financing Activities. Cash used by financing activities increased primarily due to a reduction in capital contribution from NVE, an increase in dividends paid to NVE and a reduction in cash from the issuance of debt partially offset by a decrease in debt retirements.

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. Another significant use of cash is the refunding of previously over-collected amounts from customers; however, this is partially mitigated as NPC continues to over-collect from customers as a result of current rates set above the current cost of fuel and purchased power. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions. Available liquidity as of September 30, 2012 was as follows (in millions):

Available Liquidity as of September 30, 2012 (in millions)
			NPC
Cash and Cash Equivalents			$	124.5
	Balance available on Revolving Credit Facility⁽¹⁾			497.3
			$	621.8

⁽¹⁾		As of November 6, 2012, NPC had approximately $497.3 million available under its revolving credit
		facility which includes reductions for letters of credits, as discussed below under Financing Transactions.

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.

In April 2012, NPC used $120 million from its revolving credit facility along with $10 million from cash on hand to pay for the maturity of its 6.5% General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million. NPC does not have any other debt maturities in 2012; however, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, which is currently expected no later than December 31, 2013. As of November 6, 2012, NPC has no borrowings outstanding on its $500 million revolving credit facility, not including letters of credit.

In prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NPC has transitioned to slower growth, the amount of capital expenditures required has declined. NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to better manage and optimize its resources. As a result, NPC anticipates that they will be able to meet short-term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, NPC expects to generate free cash flow. The free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities. To meet long-term maturing debt obligations, NPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.

However, if energy costs rise at a rapid rate 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 NPC could be significantly less. In order to maintain sufficient liquidity under such circumstances, NPC may be required to delay capital expenditures, re-finance debt, or receive capital contributions from NVE.

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.

During the nine months ended September 30, 2012, NPC paid dividends to NVE of $119 million. On November 7, 2012, NPC declared a dividend to NVE of $65 million.

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

During the nine months ended September 30, 2012, there were no material changes to contractual obligations as set forth in NPC’s 2011 Form 10-K.

Financing Transactions

$500 Million Revolving Credit Facility

In March 2012, NPC terminated its $600 million secured revolving credit facility (which would have expired in April 2013) and replaced it with a $500 million revolving credit facility, maturing in March 2017 and secured by NPC’s General and Refunding Mortgage Bond, Series Z, in the aggregate principal amount of $500 million (the “NPC Credit Agreement”). The administrative agent for the NPC Credit Agreement remains Wells Fargo Bank, National Association. NPC may use the facility for general corporate purposes and for the issuance of letters of credit.

Similar to the $600 million secured revolving credit facility that it replaced, the NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The NPC Credit Agreement 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 in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities' hedging program, there was no negative mark-to-market exposure for NPC as of November 6, 2012 that would impact borrowings.

Maturity of General and Refunding Mortgage Notes, Series I

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, 2012, 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, 2012, 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 $192.5 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 the NPC Credit Agreement, 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 1.00. Based on September 30, 2012 financial statements, NPC was in compliance with this covenant and could incur up to $3.0 billion 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 Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.4 billion.

Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its 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 NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2012, $3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.6 billion of General and Refunding Mortgage Securities as of September 30, 2012. That amount is determined on the basis of:

1.	70% of net utility property additions; and/or
2.	the principal amount of retired General and Refunding Mortgage Securities.

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 NPC Indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of the NPC Indenture, it will reduce the amount of securities issuable under the NPC Indenture.

Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, 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. As of September 30, 2012, the ratings are as follows:

			Rating Agency
			Fitch⁽¹⁾	Moody’s⁽²⁾	S&P⁽³⁾
NPC		Sr. Secured Debt	BBB*	Baa1*	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 rating outlook is positive, while Moody’s and S&P’s rating outlook is stable for NPC.

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 agreement 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 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, 2012 for all suppliers continuing to provide power under a WSPP agreement would approximate a $56.3 million payment or obligation to NPC. These contracts qualify for the normal purchases and normal sales 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 9, Derivatives and Hedging Activities, of the Notes to Financial Statements in the 2011 Form 10-K 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 one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of September 30, 2012, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $86.4 million. Of this amount, approximately $25.9 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $60.5 million would be required if NPC’s Senior Unsecured and Senior

Secured ratings, both are downgraded to below investment grade. During the second quarter of 2012, $17.9 million of letters of credit posted as collateral were returned from the counterparty to NPC during the period due to NPC’s unsecured credit rating becoming investment grade. In exchange, the amount of additional cash collateral that would be required in the event of a credit rating downgrade increased.

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 Credit Agreement 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. As a result of the suspension of NPC’s commodity hedging program, there was no negative mark-to-market exposure for NPC as November 1, 2012 that would impact credit availability. If deemed prudent, NPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

Cross Default Provisions

None of the financing agreements of NPC contain a cross default provision that would result in an event of default by NPC upon an event of default by 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 $34.4 million for the three months ended September 30, 2012, compared to net income of $25.3 million for the same period in 2011. During the nine months ended September 30, 2012, SPPC recognized net income of approximately $65.8 million compared to $45.4 million for the same period in 2011.

During the nine months ended September 30, 2012, SPPC paid $20 million in dividends to NVE.

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

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less energy and energy efficiency program 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
		2012		2011		Prior Year %	2012		2011		Prior Year %
Operating Revenues:
	Electric	$	212,073	$	202,263	4.9 %	$	549,886	$	545,462	0.8 %
	Gas		12,077		16,615	(27.3)%		77,543		125,357	(38.1)%
		$	224,150	$	218,878	2.4 %	$	627,429	$	670,819	(6.5)%

Energy Costs:
	Fuel for power generation		47,324		53,803	(12.0)%		115,137		141,130	(18.4)%
	Purchased power		33,999		41,615	(18.3)%		98,400		118,965	(17.3)%
	Gas purchased for resale		5,382		10,137	(46.9)%		46,491		87,753	(47.0)%
	Deferral of energy - electric - net		(5,498)		(22,095)	(75.1)%		(13,854)		(45,924)	(69.8)%
	Deferral of energy - gas - net		(853)		(1,171)	(27.2)%		(970)		3,520	(127.6)%
Energy efficiency program costs			4,092		2,596	57.6 %		11,143		2,596	329.2 %
	Total Costs	$	84,446	$	84,885	(0.5)%	$	256,347	$	308,040	(16.8)%

Cost by Segment:
	Electric	$	79,917	$	75,919	5.3 %	$	210,826	$	216,767	(2.7)%
	Gas		4,529		8,966	(49.5)%		45,521		91,273	(50.1)%
		$	84,446	$	84,885	(0.5)%	$	256,347	$	308,040	(16.8)%

Gross Margin by Segment:
	Electric	$	132,156	$	126,344	4.6 %	$	339,060	$	328,695	3.2 %
	Gas		7,548		7,649	(1.3)%		32,022		34,084	(6.0)%
Gross Margin		$	139,704	$	133,993	4.3 %	$	371,082	$	362,779	2.3 %

Electric gross margin increased $5.8 million for the three months ended September 30, 2012, compared to the same period in 2011. Approximately $5.3 million of the increase is due to an increase in customer usage. Usage increased primarily due to an increase in cooling degree days as shown in the tables below.

Electric gross margin increased $10.4 million for the nine months ended September 30, 2012, compared to the same period in 2011. Approximately $9.7 million of the increase is due to an increase in customer usage. Usage increased primarily due to an increase in cooling degree days, as shown in the tables below, and an increase in commercial usage by mining customers.

Gas gross margin did not change materially during the three months ended September 30, 2012, compared to the same period in 2011.

Gas gross margin decreased $2.1 million for the nine months ended September 30, 2012, compared to the same period in 2011, primarily due to $3.6 million of decreased usage among customers. Usage decreased primarily as result of a decrease in heating degree days, as shown in the tables below.

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

HDDs and CDDs

The following table shows the heating degree days and cooling degree days within SPPC’s service territory:


		Three Months Ended September 30,							Nine Months Ended September 30,
					2012 Change							2012 Change
		2012	2011	Normal	Prior Year		Normal		2012	2011	Normal	Prior Year		Normal
SPPC
	Heating	1	3	69	(66.7)	%	(98.6)	%	2,677	3,201	3,012	(16.4)	%	(11.1)	%
	Cooling	1,020	848	699	20.3	%	45.9	%	1,255	960	878	30.7	%	42.9	%

Electric Operating Revenue

			Three Months Ended September 30,					Nine Months Ended September 30,
							Change from					Change from
Operating Revenues:			2012		2011		Prior Year %	2012		2011		Prior Year %
	Residential		$	68,677	$	63,402	8.3 %	$	180,953	$	178,445	1.4 %
	Commercial			78,409		75,503	3.8 %		200,912		200,064	0.4 %
	Industrial			48,541		46,761	3.8 %		120,234		116,396	3.3 %
		Retail Revenues		195,627		185,666	5.4 %		502,099		494,905	1.5 %
	Other			16,446		16,597	(0.9)%		47,787		50,557	(5.5)%
		Total Operating Revenues	$	212,073	$	202,263	4.9 %	$	549,886	$	545,462	0.8 %

Retail sales in thousands of MWhs
	Residential			667		612	9.0 %		1,737		1,673	3.8 %
	Commercial			849		822	3.3 %		2,233		2,165	3.1 %
	Industrial			686		642	6.9 %		2,005		1,887	6.3 %
Retail sales in thousands of MWhs				2,202		2,076	6.1 %		5,975		5,725	4.4 %

Average retail revenue per MWh			$	88.84	$	89.43	(0.7)%	$	84.03	$	86.45	(2.8)%

Retail revenue increased by $10 million for the three months ended September 30, 2012, as compared to the same period in 2011. Contributing to the increase was approximately $6.3 million due to an increase in customer usage primarily due to an increase in CDDs during the third quarter of 2012 as outlined in the table above. Further contributing to the increase was $1.6 million attributable to customer growth and approximately $1.5 million attributable to the EEPR amortization rates effective October 1, 2011 (see Note 3, Regulatory Actions of the Notes to Financial Statements in this Form 10-Q and the 2011 Form 10-K).

For the three months ended September 30, 2012 the average number of residential, commercial, and industrial customers increased 1.0%, 0.7% and 4.4%, respectively, compared to the same period in 2011.

Retail revenue increased by $7.2 million for the nine months ended September 30, 2012, as compared to the same period in 2011. Contributing to the increase was approximately $11.8 million due to an increase in customer usage primarily due to an increase in CDDs as outlined in the table above and also due to increased usage by mining customers. Further contributing to the increase was approximately $8.5 million attributable to the implementation of EEPR base rates effective July 1, 2011, and EEPR amortization rates effective October 1, 2011, and $1.4 million due to an increase in EEIR revenue (see Note 3, Regulatory Actions of the Notes to Financial Statements in this Form 10-Q and the 2011 Form 10-K). Customer growth also contributed approximately $2.8 million to the increase. These increases were partially offset by approximately $20.0 million of rate decreases due to SPPC’s annual Deferred Energy case effective October 1, 2011, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements in this Form 10-Q and the 2011 Form 10-K).

For the nine months ended September 30, 2012, the average number of residential and industrial customers increased 0.7% and 2.8%, respectively, while commercial customers decreased 0.2% compared to the same period in 2011.

Electric Operating Revenues – Other decreased by $150 thousand for the three months ended September 30, 2012, compared to the same period in 2011. A decrease of approximately $910 thousand in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 16, Assets Held for Sale, of the Notes to Financial Statements in the 2011 Form 10-K) contributed to the decrease in electric operating revenues other. This decrease was partially offset by an increase of approximately $849 thousand in transmission service revenues.

Electric Operating Revenues – Other decreased by $2.8 million for the nine months ended September 30, 2012, compared to the same period in 2011. Approximately $4.3 million of the decrease is due to a decrease in revenues from energy sales to CalPeco, as discussed above. This decrease was partially offset by a $1.9 million increase in transmission service revenues.

Gas Operating Revenue

			Three Months Ended September 30,					Nine Months Ended September 30,
							Change from					Change from
			2012		2011		Prior Year %	2012		2011		Prior Year %
Gas Operating Revenues:
	Residential		$	7,306	$	8,582	(14.9)%	$	45,104	$	65,833	(31.5)%
	Commercial			2,583		3,398	(24.0)%		17,961		27,945	(35.7)%
	Industrial			906		1,265	(28.4)%		5,115		8,634	(40.8)%
		Retail Revenues		10,795		13,245	(18.5)%		68,180		102,412	(33.4)%
	Wholesale Revenues			563		2,615	(78.5)%		7,033		20,530	(65.7)%
	Miscellaneous			719		755	(4.8)%		2,330		2,415	(3.5)%
		Total Gas Revenues	$	12,077	$	16,615	(27.3)%	$	77,543	$	125,357	(38.1)%

Retail sales in thousands of Dths
	Residential			642		638	0.6 %		5,613		6,318	(11.2)%
	Commercial			374		389	(3.9)%		2,939		3,228	(9.0)%
	Industrial			153		160	(4.4)%		876		1,047	(16.3)%
Retail sales in thousands of Dths				1,169		1,187	(1.5)%		9,428		10,593	(11.0)%

Average retail revenue per Dth			$	9.23	$	11.16	(17.2)%	$	7.23	$	9.67	(25.2)%

SPPC’s retail gas revenues decreased $2.5 million for the three months ended September 30, 2012, compared to the same period in 2011. Approximately $2.4 million of the decrease is due to decreases in retail rates as a result of SPPC’s annual Deferred Energy case, effective October 1, 2011, and various BTER quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements).

SPPC’s retail gas revenues decreased $34.2 million for the nine months ended September 30, 2012, compared to the same periods in 2011. Approximately $27.7 million of the decrease is due to decreases in retail rates as a result of SPPC’s annual Deferred Energy case, effective October 1, 2011, and various BTER quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements). Approximately $6.7 million of the decrease was due to decreased usage. Usage decreased primarily due to a decrease in heating degree days, as shown in the table above. These decreases were partially offset by $0.2 million attributable to the implementation of STPR rates effective October 1, 2011 (see Note 3, Regulatory Actions of the Notes to Financial Statements in this Form 10-Q and the 2011 Form 10-K).

Wholesale revenues decreased for the three and nine months ended September 30, 2012 by $2.1 million and $13.6 million respectively, primarily due to a decrease in pipeline optimization.

Energy Costs

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

•		weather
•		plant outages
•		total system demand
•		resource constraints
•		transmission constraints
•		gas transportation constraints
•		natural gas constraints
•		long-term contracts
•		mandated power purchases
•		generation efficiency; and
•		volatility of commodity prices

		Three Months Ended September 30,					Nine Months Ended September 30,
						Change from					Change from
		2012		2011		Prior Year %	2012		2011		Prior Year %
Energy Costs:
	Fuel for power generation	$	47,324	$	53,803	(12.0)%	$	115,137	$	141,130	(18.4)%
	Purchased power		33,999		41,615	(18.3)%		98,400		118,965	(17.3)%
Total Energy Costs		$	81,323	$	95,418	(14.8)%	$	213,537	$	260,095	(17.9)%

MWhs
	MWhs Generated (in thousands)		1,512		1,301	16.2 %		3,829		3,339	14.7 %
	Purchased Power (in thousands)		971		1,057	(8.1)%		3,031		3,260	(7.0)%
Total MWhs			2,483		2,358	5.3 %		6,860		6,599	4.0 %

Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	31.30	$	41.36	(24.3)%	$	30.07	$	42.27	(28.9)%
	Average cost per MWh of Purchased Power	$	35.01	$	39.37	(11.1)%	$	32.46	$	36.49	(11.0)%
	Average total cost per MWh	$	32.75	$	40.47	(19.1)%	$	31.13	$	39.41	(21.0)%

Energy costs and average cost per MWh decreased for the three and nine months ended September 30, 2012, compared to the same period in 2011, primarily due to lower natural gas prices, and for the nine month period a decrease in costs associated with hedging activities. Total MWhs increased for the three and nine month periods primarily due to an increase in CDDs, and in the case of the nine months, an increase in usage by mining customers.

•

Fuel for generation costs decreased $6.5 million for the three months ended September 30, 2012, compared to the same period in 2011. Approximately $13.7 million of the change is due to lower natural gas prices partially offset by an increase in volume of approximately $6.6 million and a slight increase in the price of coal of approximately $1.2 million.

Fuel for generation costs decreased $26.0 million for the nine months ended September 30, 2012, compared to the same period in 2011. Approximately $37.0 million of the change is due to lower natural gas prices. Fuel for generation costs were further decreased by $5.6 million due to a decrease in hedging activities. These decreases were partially offset by an increase in volume of approximately $13.5 million and an increase in the price of coal of approximately $3.1 million.

•

Purchased power costs decreased $7.6 million for the three months ended September 30, 2012, compared to the same period in 2011. Approximately $4.1 million of the decrease is due to lower natural gas prices and approximately $2.6 million is due to decreased volume. Volume decreased due to increased reliance on internal generation.

Purchased power costs decreased $20.6 million for the nine months ended September 30, 2012, compared to the same period in 2011. Approximately $12.9 million of the decrease is due to lower natural gas prices and approximately $6.4 million is due to decreased volume. Volume decreased due to increased reliance on internal generation.

Gas Purchased for Resale

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %

Gas purchased for resale	$	5,382	$	10,137	(46.9)%	$	46,491	$	87,753	(47.0)%
Gas purchased for resale (in thousands of Dths)		1,349		1,859	(27.4)%		12,636		15,696	(19.5)%
Average cost per Dth	$	3.99	$	5.45	(26.8)%	$	3.68	$	5.59	(34.2)%

Gas purchased for resale decreased by $4.8 million for the three months ended September 30, 2012, compared to the same period in 2011. Approximately $2.6 million of the decrease is due to lower natural gas prices and approximately $2.0 million is due to a decrease in volume. Volume decreased primarily due to a decrease in pipeline optimization.

Gas purchased for resale decreased by $41.3 million for the nine months ended September 30, 2012, compared to the same period in 2011. Approximately $24.6 million of the decrease is due to lower natural gas prices and approximately $11.3 million is due to a decrease in volume. Volume decreased primarily due to a decrease in pipeline optimization and a decrease in heating degree days. Also contributing to the decrease in gas purchased for resale was a decrease in costs associated with hedging activities of approximately $5.4 million for the nine month period.

Deferred Energy

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %

Deferral of energy - electric - net	$	(5,498)	$	(22,095)	(75.1)%	$	(13,854)	$	(45,924)	(69.8)%
Deferral of energy - gas - net		(853)		(1,171)	(27.2)%		(970)		3,520	(127.6)%
	$	(6,351)	$	(23,266)		$	(14,824)	$	(42,404)

Deferred energy – electric for the three months ended September 30, 2012 and 2011 include amortization of deferred energy of ($19.3) million and ($27.1) million respectively; and an over-collection of amounts recoverable in rates of $13.8 million and $5.0 million, respectively. Amounts for the nine months ended September 30, 2012 and 2011, include amortization of deferred energy of ($65.0) million and ($75.5) million, respectively; and an over-collection of amounts recoverable in rates of $51.2 million and $29.5 million, respectively.

Deferred energy – gas for the three months ended September 30, 2012 and 2011 include amortization of deferred energy of ($2.2) million and ($1.3) million respectively; and an over-collection of amounts recoverable in rates of $1.3 million and $0.2 million, respectively. Amounts for the nine months ended September 30, 2012 and 2011, include amortization of deferred energy of ($19.9) million and ($12.0) million, respectively; and an over-collection of amounts recoverable in rates of $18.9 million and $15.5 million, respectively.

Other Operating Expenses

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %

Energy efficiency program costs	$	4,092	$	2,596	57.6 %	$	11,143	$	2,596	329.2 %
Other operating expenses	$	34,128	$	35,933	(5.0)%	$	104,214	$	110,836	(6.0)%
Maintenance	$	6,481	$	7,909	(18.1)%	$	23,596	$	28,195	(16.3)%
Depreciation and amortization	$	27,537	$	26,525	3.8 %	$	80,594	$	79,647	1.2 %

For the three and nine months ended September 30, 2012 energy efficiency program costs increased $1.5 million and $8.5 million, respectively, compared to the prior year primarily due to the implementation of EEPR base rates in July 2011 and in the case of the nine month period, EEPR amortization rates effective October 2011.

Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR base rates and amortization rates which were implemented in July 2011 for base rates and in October 2011 for amortization rates (See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K). Costs incurred prior to the implementation of the EEPR rates are recovered through general rates and amortized to other operating expense discussed below. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any under/over collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income, or net income.

Other operating expenses decreased $1.8 million for the three months ended September 30, 2012, compared to the same period in 2011, primarily due to $2.3 million in lower pension and benefit costs, and a $0.6 million decrease in stock compensation costs. The decrease was partially offset by a $1.1 million increase in outside legal consulting fees.

Other operating expenses decreased $6.6 million for the nine months ended September 30, 2012, compared to the same period in 2011, primarily due to $3.3 million in lower pension and benefit costs, $1.7 million in lower expenses for rate cases, $1.6 million in lower transmission and distribution costs, and $0.6 million lower reserves for uncollectible accounts. The decrease was partially offset by a $0.9 million increase in outside legal consulting fees.

Maintenance expense decreased $1.4 million for the three months ended September 30, 2012, compared to the same period in 2011, primarily due to 2011 planned major outages at the Ft. Churchill and Valmy Generating Stations.

Maintenance expense decreased $4.6 million for the nine months ended September 30, 2012, compared to the same period in 2011, primarily due to $6.2 million of planned maintenance outages in 2011 at the Valmy Generating Station, offset by $2.4 million of planned maintenance outages in 2012 at the Tracy Generating Station.

Depreciation and amortization increased slightly for the three and nine months ended September 30, 2012, compared to the same period in 2011, primarily due to general increases in plant-in-service.

Interest Expense

	Three Months Ended September 30,					Nine Months Ended September 30,
					Change from					Change from
	2012		2011		Prior Year %	2012		2011		Prior Year %
Interest expense
(net of AFUDC-debt: $448, $484, $1,458 and $1,409)	$	15,298	$	16,861	(9.3)%	$	47,650	$	50,581	(5.8)%

Interest expense decreased $1.6 million and $2.9 million for the three and nine month ended September 30, 2012, respectively, compared to the same period in 2011 primarily due to decreased debt amortization expense of $1.5 million for the three months and $2.7 million for the nine months. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2011 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
	2012		2011		Prior Year %		2012		2011		Prior Year %

Interest expense on regulatory items	$	(401)	$	(1,200)	(66.6)	%	$	(715)	$	(4,228)	(83.1)	%
AFUDC-equity	$	582	$	664	(12.3)	%	$	1,843	$	1,875	(1.7)	%
Other income	$	1,399	$	810	72.7	%	$	4,181	$	2,676	56.2	%
Other expense	$	(998)	$	(2,255)	(55.7)	%	$	(3,609)	$	(7,403)	(51.2)	%

The decrease in interest expense on regulatory items of approximately $800 thousand and $3.5 million for the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011 is primarily attributable to interest expense related to lower over-collected deferred energy balances in 2012 of $700 thousand and $2.7 million for the three and nine month periods, respectively.

AFUDC-equity did not change materially for the three and nine months ended September 30, 2012 compared to the same periods in 2011.

Other income did not change materially for the three months ended September 30, 2012, compared to the same period in 2011.

Other income increased approximately $1.5 million for the nine months ended September 30, 2012, compared to the same period in 2011. The increase is primarily due to the $1.1 million settlement with CA ISO in 2011 recognized in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2011 Form 10-K.

Other expense decreased $1.3 million for the three months ended September 30, 2012, as compared to the same period in 2011 primarily due to $0.7 million losses on investments in 2011 and $0.5 million adjustments for the settlement of the deferred energy rate case in 2011, offset slightly by $0.2 million adjustment for the settlement of the deferred energy rate case in 2012. For further discussion of the DEAA adjustment see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K.

Other expense decreased $3.8 million for the nine months ended September 30, 2012, as compared to the same period in 2011 primarily due to the $2.8 million adjustment, recorded in 2011, as a result of an order from the PUCN adjusting EEIR revenue recorded in 2010. For further discussion of the EEIR adjustment see Note 3, Regulatory Actions, EEIR, of the Notes to Financial Statements in the 2011 Form 10-K. Adding to the decrease was $0.7 million losses on investments in 2011 and $0.5 million adjustment for the settlement of the deferred energy rate case in 2011, offset slightly by $0.2 million adjustment for the settlement of the deferred energy rate case in 2012. For further discussion of the DEAA adjustment see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K and Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements.

Analysis of Cash Flows

SPPC’s cash flows decreased during the nine months ended September 30, 2012, compared to the same period in 2011, due to a decrease in cash from investing activities, offset partially by a slight increase in cash from operating activities and a reduction in cash used by financing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to increased customer usage, a reduction in refunds of over collected balances for energy, increased customer deposits, and over collections of EEPR. These increases were partially offset by increased energy payments due to a change in terms with energy counterparties from weekly to monthly settlements in mid-2011, higher rebates for wind energy in 2012, the receipt of cash in 2011 under the affiliate tax sharing agreement, increased funding of the retirement plan and the timing of property tax payments.

Cash From Investing Activities. The decrease in cash from investing activities was primarily due to the receipt of proceeds from the sale of California Assets in 2011 and increased capital expenditures for the NV Energize project in 2012.

Cash Used By Financing Activities. The decrease in cash used by financing activities is primarily due to a reduction in dividends to NVE and the repayment of draws under SPPC’s revolving credit facility in 2011.

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. Another significant use of cash is the refunding of previously over-collected amounts from customers; however, this is partially mitigated as SPPC continues to over-collect from customers as a result of current rates set above the current cost of fuel and purchased power. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions. Available liquidity as of September 30, 2012 was as follows (in millions):

Available Liquidity as of September 30, 2012 (in millions)
			SPPC
Cash and Cash Equivalents			$	51.7
	Balance available on Revolving Credit Facility⁽¹⁾			239.5
			$	291.2

⁽¹⁾		As of November 6, 2012, SPPC had approximately $243.7 million available under its revolving credit facility
		which includes reductions for letters of credits, as discussed below under Financing Transactions.

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 2012. However, SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013. As of November 6, 2012, SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including letters of credit.

In prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As SPPC has transitioned to slower growth, the amount of capital expenditures required has declined. SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources. As a result, SPPC anticipates that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility. Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow. The free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities. To meet long term

maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.

However, if energy costs rise at a rapid rate, 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 under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from 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.

During the nine months ended September 30, 2012, SPPC paid dividends to NVE of $20 million.

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

During the nine months ended September 30, 2012, there were no material changes to contractual obligations as set forth in SPPC’s 2011 Form 10-K.

Financing Transactions

$250 Million Revolving Credit Facility

In March 2012, SPPC terminated its $250 million secured revolving credit facility (which would have expired in April 2013) and replaced it with a $250 million revolving credit facility, maturing in March 2017 and secured by SPPC’s General and Refunding Mortgage Bond, Series S, in the aggregate principal amount of $250 million (the “SPPC Credit Agreement”). The administrative agent for the SPPC Credit Agreement is Wells Fargo Bank, National Association. SPPC may use the facility for general corporate purposes and for the issuance of letters of credit.

The rate for outstanding loans under the SPPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon SPPC’s secured debt credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 0.5% and the LIBOR rate margin is 1.5%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

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 1.00. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. As of September 30, 2012, SPPC was in compliance with this covenant requirement. 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.

Similar to the $250 million secured revolving credit facility that it replaced, the SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 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, 2012, 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, 2012, 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. On July 9, 2012, SPPC filed a new financing application with the PUCN which did not differ substantially from the current authority. SPPC expects a decision on the application by December 2012;

b.	Financial covenants within SPPC’s financing agreements – Under the SPPC Credit Agreement, 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 1.00. Based on September 30, 2012 financial statements, SPPC was in compliance with this covenant and could incur up to $979.5 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 Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.4 billion.

Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its 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 SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of September 30, 2012, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $832.0 million of additional General and Refunding Mortgage Securities as of September 30, 2012. That amount is determined on the basis of:

1.	70% of net utility property additions; and/or
2.	the principal amount of retired General and Refunding Mortgage Securities.

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

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

Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, 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. As of September 30, 2012, the ratings are as follows:

		Rating Agency
		Fitch⁽¹⁾	Moody’s⁽²⁾	S&P⁽³⁾
SPPC	Sr. Secured Debt	BBB*	Baa1*	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 rating outlook is positive, while Moody’s and S&P’s rating outlook is stable for SPPC.

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 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. According to the net mark-to-market value as of September 30, 2012, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement. These contracts qualify for the normal purchases and normal sales scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements in the 2011 Form 10-K 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.

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 Credit Agreement 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. As a result of the suspension of SPPC’s commodity hedging program, there was no negative mark-to-market exposure for SPPC as of November 1, 2012 that would impact credit availability. If deemed prudent, SPPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

Cross Default Provisions

None of the financing agreements of SPPC contain 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 Notes to Financial Statements and in the 2011 Form 10-K for discussion of accounting policies and recent pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2012, 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):

					2012
					Expected Maturities
																									Fair
				2012		2013			2014			2015			2016			Thereafter			Total				Value
Long-Term Debt
	NVE
	Fixed Rate			$	-	$	-		$	195,000		$	-		$	-		$	315,000		$	510,000		$	559,001
		Average Interest Rate			-		-			2.81	%		-			-			6.25	%		4.93	%		-

	NPC
	Fixed Rate			$	-	$	-		$	125,000		$	250,000		$	210,000		$	2,545,000		$	3,130,000		$	3,960,594
		Average Interest Rate			-		-			7.38	%		5.88	%		5.95	%		6.47	%		6.42	%		-

	Variable Rate			$	-	$	-		$	-		$	-		$	-		$	173,775		$	173,775		$	170,167
		Average Interest Rate			-		-			-			-			-			0.71	%		0.71	%		-

	SPPC
	Fixed Rate			$	-	$	250,000		$	-		$	-		$	450,000		$	251,742		$	951,742		$	1,139,062
		Average Interest Rate			-		5.45	%		-			-			6.00	%		6.75	%		6.05	%		-

	Variable Rate			$	-	$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	190,989
		Average Interest Rate			-		-			-			-			-			0.68	%		0.68	%		-

			TOTAL DEBT	$	-	$	250,000		$	320,000		$	250,000		$	660,000		$	3,500,192		$	4,980,192		$	6,019,813

Commodity Price Risk

See the 2011 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, 2011.

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 $59.0 million as of September 30, 2012, which compares to balances of $49.0 million at June 30, 2012, and $41.6 million at March 31, 2012.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of September 30, 2012, the registrants’ disclosure controls and procedures were effective.

(b) Change in internal controls over financial reporting.

There were no changes in the registrants’ internal controls over financial reporting in the third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal controls over financial reporting.

PART II - OTHER INFORMATION

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 7, 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 2011 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 2011 Form 10-K, and quarterly reports for NVE, NPC and SPPC on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.

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

Issuer Purchases of Equity Securities

The following table contains information about NVE’s purchases of common stock for the quarter ended September 30, 2012:

					Total Number of Shares	Maximum Number of
					Purchased as Part of	Shares that may yet be
		Total Number of		Average Price Paid	Publicly Announced	Purchased Under the
Period		Shares Purchased		Per Share	Plans or Programs	Plans or Programs

July 1-July 31, 2012		-		-	-	-
August 1-August 31, 2012		-		-	-	-
September 1-September 30, 2012		252,000	$	17.87	-	-
	Total	252,000	$	17.87	-	-

⁽¹⁾	Represents shares of common stock purchased on the open market to provide shares to participants under various NVE stock compensation plans. These purchases were not made pursuant to a publicly announced stock repurchase plan or program.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

(12) NV Energy, Inc.:

12.1	Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company:

12.2	Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company:

12.3	Statement regarding computation of Ratios of Earnings to Fixed Charges.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(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

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 8, 2012	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)

Date: November 8, 2012	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 8, 2012	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)

Date: November 8, 2012	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 8, 2012	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)

Date: November 8, 2012	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

Positive
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Uncertain
Constraining
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Litigous
Readability	H.S. sophomore Avg

Sierra Pacific Power 10-Q2012 FY Quarterly report

Content analysis

NOTE 9. COMMON STOCK AND OTHER PAID-IN CAPITAL