Sierra Pacific Power 10Q 2009 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 2009

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 Web site, 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______ No______ (Response applicable to all registrants)

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

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

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

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

Class		Outstanding at July 31, 2009
Common Stock, $1.00 par value of NV Energy, Inc.		234,617,948 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 JUNE 30, 2009

TABLE OF CONTENTS

Acronyms and Terms..................................................................................................................................................................................................................................................................			3

		PART I - FINANCIAL INFORMATION

ITEM 1.		Financial Statements

	NV Energy, Inc. -
		Consolidated Balance Sheets - June 30, 2009 and December 31, 2008 ...........................................................................................................................................	5
		Consolidated Statements of Operations - Three and Six Months Ended June 30, 2009 and 2008..............................................................................................	6
		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2009 and 2008................................................................................................................	7

	Nevada Power Company -
		Consolidated Balance Sheets - June 30, 2009 and December 31, 2008............................................................................................................................................	8
		Consolidated Statements of Operations - Three and Six Months Ended June 30, 2009 and 2008..............................................................................................	9
		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2009 and 2008................................................................................................................	10

	Sierra Pacific Power Company -
		Consolidated Balance Sheets - June 30, 2009 and December 31, 2008............................................................................................................................................	11
		Consolidated Statements of Income - Three and Six Months Ended June 30, 2009 and 2008.....................................................................................................	12
		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2009 and 2008................................................................................................................	13

		Condensed Notes to Consolidated Financial Statements.................................................................................................................................................................	14

ITEM 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations...................................................................................................	30

		NV Energy, Inc.........................................................................................................................................................................................................................................	34
		Nevada Power Company........................................................................................................................................................................................................................	40
		Sierra Pacific Power Company...............................................................................................................................................................................................................	48

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

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

		PART II - OTHER INFORMATION

ITEM 1.		Legal Proceedings..................................................................................................................................................................................................................................	59

ITEM 1A.		Risk Factors ...........................................................................................................................................................................................................................................	59

ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds.......................................................................................................................................................	59

ITEM 3.		Defaults Upon Senior Securities.........................................................................................................................................................................................................	59

ITEM 4.		Submission of Matters to a Vote of Security Holders......................................................................................................................................................................	60

ITEM 5.		Other Information...................................................................................................................................................................................................................................	60

ITEM 6.		Exhibits.....................................................................................................................................................................................................................................................	61

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

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

Acronyms/Terms		Meaning

2008 Form 10-K		NVE’s NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2008
AFUDC		Allowance for Funds Used During Construction or Allowance for Borrowed Funds Used During Construction
APB 28-1		Accounting Principles Board 28-1, “Interim Financial Reporting”
BOD		Board of Directors
BTER		Base Tariff Energy Rate
BTGR		Base Tariff General Rate
Calpine		Calpine Corporation
Clark Generating Station		550 megawatt nominally rated William Clark Generating Station
Clark Peaking Units		600 megawatt nominally rated peaking units at the William Clark Generating Station
CPUC		California Public Utilities Commission
CWIP		Construction Work-In-Progress
d/b/a		Doing business as
DBRS		Dominion Bond Rating Service
DEAA		Deferred Energy Accounting Adjustment
DOS		Distribution Only Service
DSM		Demand Side Management
Dth		Decatherm
EEC		Ely Energy Center
EPA		Environmental Protection Agency
EPS		Earnings Per Share
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN 46 (R)		Interpretation No. 46, “Consolidation of Variable Interest Entities”
FIN 48		Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
Fitch		Fitch Ratings, Ltd.
FSP FAS 107-1		FASB Staff Position No. 107-1, “Interim Disclosure about Fair Value of Financial Instruments”
FSP FAS 157-2		FASB Staff Position No. 157-2, “Defers the effective date for certain portions of SFAS 157 related to nonrecurring measurement of nonfinancial assets and liabilities”
FSP FAS 157-4		FASB Staff Position No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that are not Orderly”
GAAP		Accounting Principles Generally Accepted in the United States
GRC		General Rate Case
Harry Allen Generating Station		142 megawatt nominally rated Harry Allen Generating Station
Higgins Generating Station		598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
IRS		Internal Revenue Service
Lenzie Generating Station		1,102 megawatt nominally rated Chuck Lenzie Generating Station
MMBtu		Million British Thermal Units
Moody’s		Moody’s Investors Services, Inc.
MW		Megawatt
MWh		Megawatt hour
Navajo Generating Station		255 megawatt nominally rated Navajo Generating Station
NEICO		Nevada Electrical Investment Company
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NPC		Nevada Power Company d/b/a NV Energy
NPC's Indenture		NPC's General and Refunding Mortgage Indenture, dated as of May 1, 2001, between NPC and the Bank of New York Mellon, as Trustee
NVE		NV Energy, Inc.
ON Line		250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC		Portfolio Energy Credit
Piñon Pine		Piñon Pine Coal Gasification Demonstration Project
Portfolio Standard		Renewable Energy Portfolio Standard
PUCN		Public Utilities Commission of Nevada
Reid Gardner Generating Station		325 megawatt nominally rated Reid Gardner Generating Station
ROE		Return on Equity
ROR		Rate of Return
S&P		Standard and Poor’s
Salt River		Salt River Project
SEC		Securities and Exchange Commission
SFAS 71		Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 131		Statement of Financial Accounting Standards No. 131, "Disclosure About Segments of an Enterprise and Related Information"
SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 138		Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133"
SFAS 149		Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
SFAS 155		Statement of Financial Accounting Standards No. 155, "Accounting for Certain Hybrid Financial Instruments - An Amendment of FASB Statements No. 133 and 140"
SFAS 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”
SFAS 158		Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS 161		Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activity”
SFAS 165		Statement of Financial Accounting Standards No. 165, “Subsequent Events”
SFAS 167		Statement of Financial Accounting Standards No. 167, “Amendments to FASB Interpretation No. 46(R)”
SFAS 168		Statement of Financial Accounting Standards No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles a Replacement of FASB Statement No. 162”
Silverhawk Generating Station		395 megawatt nominally rated Silverhawk Generating Station
SPPC		Sierra Pacific Power Company d/b/a NV Energy
SPPC's Indenture		SPPC's General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and the Bank of New York Mellon, as Trustee
TMWA		Truckee Meadows Water Authority

Tracy Generating Station		541 megawatt nominally rated Frank A. Tracy Generating Station
U.S.		United States of America
Utilities		Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station		261 megawatt nominally rated Valmy Generating Station
WSPP		Western Systems Power Pool

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		June 30,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	10,594,076	$	10,175,741
Less accumulated provision for depreciation			2,762,031		2,603,287
			7,832,045		7,572,454
Construction work-in-progress			603,385		605,163
			8,435,430		8,177,617

Investments and other property, net			25,006		25,181

Current Assets:
Cash and cash equivalents			76,484		54,359
Accounts receivable less allowance for uncollectible accounts:
	2009 - $30,340, 2008 - $32,884		445,816		410,184
Deferred energy costs - electric (Note 3)			39,743		50,436
Materials, supplies and fuel, at average cost			124,064		124,271
Risk management assets (Note 6)			19,380		16,118
Current income taxes receivable			-		5,487
Deferred income taxes			139,587		49,996
Other			46,924		52,633
			891,998		763,484
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			145,108		231,027
Regulatory assets			1,374,656		1,415,286
Regulatory asset for pension plans			398,534		413,544
Risk management assets (Note 6)			11,740		9,959
Other			173,391		169,266
			2,103,429		2,239,082
Assets Held for Sale (Note 12)			143,020		142,506
TOTAL ASSETS		$	11,598,883	$	11,347,870
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,083,773	$	3,131,186
Long-term debt			5,571,799		5,266,982
			8,655,572		8,398,168
Current Liabilities:
Current maturities of long-term debt			9,085		9,291
Accounts payable			329,307		400,084
Accrued expenses			132,356		131,720
Risk management liabilities (Note 6)			305,931		313,846
Other			145,470		115,606
			922,149		970,547
Commitments and Contingencies (Note 7)

Deferred Credits and Other Liabilities:
Deferred income taxes			1,026,215		920,481
Deferred investment tax credit			24,451		25,923
Accrued retirement benefits			263,930		288,841
Risk management liabilities			14,393		53,403
Regulatory liabilities			363,310		350,526
Other			304,212		315,881
			1,996,511		1,955,055
Liabilities Held for Sale (Note 12)			24,651		24,100
TOTAL CAPITALIZATION AND LIABILITIES		$	11,598,883	$	11,347,870

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

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

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008

OPERATING REVENUES:
Electric	$	806,683		$	806,638		$	1,480,950		$	1,526,088
Gas		31,948			32,152			112,941			117,746
Other		10			4			17			11
		838,641			838,794			1,593,908			1,643,845
OPERATING EXPENSES:
Operation:
Fuel for power generation		204,285			270,625			434,389			492,233
Purchased power		194,970			261,450			320,357			445,306
Gas purchased for resale		19,916			27,632			90,188			94,528
Deferral of energy costs - electric - net		89,589			(21,386	)		139,575			32,896
Deferral of energy costs - gas - net		3,988			(3,774	)		(363	)		(1,571	)
Other		109,886			98,647			224,563			190,322
Maintenance		27,632			21,472			62,032			44,594
Depreciation and amortization		80,323			64,341			158,371			126,411
Taxes:
Income taxes (benefit)		4,084			12,928			(9,572	)		21,547
Other than income		13,753			12,658			28,400			26,565
		748,426			744,593			1,447,940			1,472,831
OPERATING INCOME		90,215			94,201			145,968			171,014

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		8,548			13,113			14,766			25,070
Interest accrued on deferred energy		(254	)		457			926			1,693
Other income		18,402			4,532			23,460			18,204
Other expense		(9,460	)		(4,770	)		(15,038	)		(7,797	)
Income taxes		(5,509	)		(4,099	)		(7,751	)		(12,188	)
		11,727			9,233			16,363			24,982
Total Income Before Interest Charges		101,942			103,434			162,331			195,996

INTEREST CHARGES:
Long-term debt		83,191			70,388			161,748			140,343
Other		7,390			7,000			16,612			14,701
Allowance for borrowed funds used during construction		(7,022	)		(10,088	)		(12,168	)		(19,240	)
		83,559			67,300			166,192			135,804

NET INCOME (LOSS)	$	18,383		$	36,134		$	(3,861	)	$	60,192

Amount per share basic and diluted - (Note 8)
Net Income/(Loss) per share – basic and diluted	$	0.08		$	0.15		$	(0.02	)	$	0.26

Weighted Average Shares of Common Stock Outstanding - basic		234,474,727			233,992,721			234,403,282			233,914,046
Weighted Average Shares of Common Stock Outstanding - diluted		235,089,193			234,519,562			234,403,282			234,420,336
Dividends Declared Per Share of Common Stock	$	0.10		$	0.08		$	0.20		$	0.16

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

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

	Six Months Ended
	June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	(3,861	)	$	60,192
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		158,371			126,411
Deferred taxes and deferred investment tax credit		68,588			88,346
AFUDC		(14,766	)		(25,070	)
Amortization of energy costs, net of deferrals		141,802			33,388
Other, net		37,256			(10,992	)
Changes in certain assets and liabilities:
Accounts receivable		(28,876	)		(63,653	)
Materials, supplies and fuel		284			(2,717	)
Other current assets		5,709			8,929
Accounts payable		(26,988	)		9,690
Accrued retirement benefits		(24,910	)		12,642
Other current liabilities		(14,453	)		11,414
Risk management assets and liabilities		(2,574	)		(9,837	)
Other deferred assets		(8,653	)		(18,019	)
Other regulatory assets		(27,094	)		(32,812	)
Other deferred liabilities		(66,354	)		178
Net Cash from Operating Activities		193,481			188,090

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(457,483	)		(471,675	)
Customer advances for construction		(3,144	)		(2,297	)
Contributions in aid of construction		29,855			41,994
Investments and other property - net		(169	)		4,379
Net Cash used by Investing Activities		(430,941	)		(427,599	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,036,957			428,000
Retirement of long-term debt		(733,761	)		(214,070	)
Sale of Common Stock		3,311			4,795
Dividends paid		(46,922	)		(37,531	)
Net Cash from Financing Activities		259,585			181,194

Net Increase (Decrease) in Cash and Cash Equivalents		22,125			(58,315	)
Beginning Balance in Cash and Cash Equivalents		54,359			129,140
Ending Balance in Cash and Cash Equivalents	$	76,484		$	70,825

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	154,680		$	143,472
Income taxes	$	14		$	15,553

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

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		June 30,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	7,263,568	$	6,884,033
Less accumulated provision for depreciation			1,632,351		1,500,502
			5,631,217		5,383,531
Construction work-in-progress			481,155		514,096
			6,112,372		5,897,627

Investments and other property, net			19,590		19,701

Current Assets:
Cash and cash equivalents			35,907		28,594
Accounts receivable less allowance for uncollectible accounts:
	2009 - $27,912, 2008 - $30,621		319,316		238,379
Deferred energy costs - electric (Note 3)			39,743		50,436
Materials, supplies and fuel, at average cost			71,816		74,103
Risk management assets (Note 6)			15,620		11,724
Intercompany income taxes receivable			52,478		20,695
Deferred income taxes			7,497		2,682
Other			33,599		34,657
			575,976		461,270
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			145,108		231,027
Regulatory assets			954,849		971,354
Regulatory asset for pension plans			181,049		187,894
Risk management assets (Note 6)			9,174		7,346
Other			131,105		127,928
			1,421,285		1,525,549
TOTAL ASSETS		$	8,129,223	$	7,904,147
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,542,948	$	2,627,567
Long-term debt			3,712,016		3,385,106
			6,254,964		6,012,673
Current Liabilities:
Current maturities of long-term debt			9,085		8,691
Accounts payable			243,069		262,552
Accounts payable, affiliated companies			18,365		32,901
Accrued expenses			85,915		80,069
Dividends declared			25,000		-
Risk management liabilities (Note 6)			219,091		222,856
Other			57,116		72,762
			657,641		679,831
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
Deferred income taxes			696,363		635,523
Deferred investment tax credit			9,421		10,001
Accrued retirement benefits			89,852		103,023
Risk management liabilities (Note 6)			10,868		35,241
Regulatory liabilities			196,609		188,709
Other			213,505		239,146
			1,216,618		1,211,643
TOTAL CAPITALIZATION AND LIABILITIES		$	8,129,223	$	7,904,147

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
OPERATING REVENUES:
Electric	$	575,769		$	570,223		$	1,012,298		$	1,039,395

OPERATING EXPENSES:
Operation:
Fuel for power generation		140,333			209,920			294,395			373,941
Purchased power		165,292			164,087			253,498			257,837
Deferral of energy costs - net		59,809			(9,691	)		97,999			36,084
Other		68,057			62,617			138,250			119,712
Maintenance		18,732			13,608			46,266			30,258
Depreciation and amortization		53,510			42,323			105,873			82,953
Taxes:
Income taxes (benefit)		1,035			12,865			(17,512	)		14,997
Other than income		8,361			7,427			17,424			15,749
		515,129			503,156			936,193			931,531
OPERATING INCOME		60,640			67,067			76,105			107,864

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		7,552			7,692			13,173			14,550
Interest accrued on deferred energy		790			1,084			2,643			2,878
Other income		12,608			3,107			14,950			8,854
Other expense		(7,591	)		(1,656	)		(10,798	)		(3,017	)
Income taxes		(4,361	)		(3,131	)		(6,543	)		(7,522	)
		8,998			7,096			13,425			15,743
Total Income Before Interest Charges		69,638			74,163			89,530			123,607

INTEREST CHARGES:
Long-term debt		57,512			41,624			109,820			82,621
Other		5,731			5,384			13,028			11,215
Allowance for borrowed funds used during construction		(6,106	)		(6,020	)		(10,668	)		(11,375	)
		57,137			40,988			112,180			82,461

NET INCOME (LOSS)	$	12,501		$	33,175		$	(22,650	)	$	41,146


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

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

	Six Months Ended
	June 30,
	2009			2008
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
Net Income (Loss)	$	(22,650	)	$	41,146
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		105,873			82,953
Deferred taxes and deferred investment tax credit		51,494			18,119
AFUDC		(13,173	)		(14,550	)
Amortization of energy costs, net of deferrals		96,612			33,315
Other, net		19,797			(8,562	)
Changes in certain assets and liabilities:
Accounts receivable		(112,720	)		(76,989	)
Materials, supplies and fuel		2,287			726
Other current assets		1,056			2,385
Accounts payable		(6,278	)		19,379
Accrued retirement benefits		(13,172	)		7,789
Other current liabilities		(9,799	)		17,405
Risk management assets and liabilities		(3,442	)		(9,406	)
Other deferred assets		(6,767	)		(18,731	)
Other regulatory assets		(22,999	)		(21,859	)
Other deferred liabilities		(23,872	)		1,357
Net Cash from Operating Activities		42,247			74,477

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(349,092	)		(352,560	)
Customer advances for construction		(966	)		(3,969	)
Contributions in aid of construction		26,103			33,869
Investments and other property - net		1			2,795
Net Cash used by Investing Activities		(323,954	)		(319,865	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		876,346			225,000
Retirement of long-term debt		(550,326	)		(88,218	)
Additional investment by parent company		-			133,000
Dividends paid		(37,000	)		(24,907	)
Net Cash from Financing Activities		289,020			244,875

Net Increase (Decrease) in Cash and Cash Equivalents		7,313			(513	)
Beginning Balance in Cash and Cash Equivalents		28,594			37,001
Ending Balance in Cash and Cash Equivalents	$	35,907		$	36,488

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	101,626		$	84,783
Income taxes	$	2		$	15,534

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

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

		June 30,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	3,330,508	$	3,291,708
Less accumulated provision for depreciation			1,129,680		1,102,785
			2,200,828		2,188,923
Construction work-in-progress			122,230		91,067
			2,323,058		2,279,990

Investments and other property, net			339		403

Current Assets:
Cash and cash equivalents			19,110		21,411
Accounts receivable less allowance for uncollectible accounts:
	2009 - $2,428; 2008 - $2,262		126,283		171,729
Materials, supplies and fuel, at average cost			52,185		50,132
Risk management assets (Note 6)			3,760		4,394
Intercompany income taxes receivable			51,136		64,932
Deferred income taxes			27,257		12,253
Other			12,458		17,631
			292,189		342,482
Deferred Charges and Other Assets:
Regulatory assets			419,807		443,932
Regulatory asset for pension plans			210,751		218,550
Risk management assets (Note 6)			2,566		2,613
Other			34,624		33,959
			667,748		699,054
Assets Held for Sale (Note 12)			143,020		142,506
TOTAL ASSETS		$	3,426,354	$	3,464,435
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	970,218	$	877,961
Long-term debt			1,373,992		1,395,987
			2,344,210		2,273,948
Current Liabilities:
Current maturities of long-term debt			-		600
Accounts payable			66,013		109,410
Accounts payable, affiliated companies			16,917		17,433
Accrued expenses			34,107		37,787
Dividends declared			5,000		96,800
Risk management liabilities (Note 6)			86,840		90,990
Other			88,353		42,844
			297,230		395,864
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
Deferred income taxes			334,544		287,251
Deferred investment tax credit			15,030		15,922
Accrued retirement benefits			168,495		180,209
Risk management liabilities (Note 6)			3,525		18,162
Regulatory liabilities			166,701		161,817
Other			71,968		107,162
			760,263		770,523
Liabilities Held for Sale (Note 12)			24,651		24,100
TOTAL CAPITALIZATION AND LIABILITIES		$	3,426,354	$	3,464,435

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
OPERATING REVENUES:
Electric	$	230,914		$	236,415		$	468,652		$	486,693
Gas		31,948			32,152			112,941			117,746
		262,862			268,567			581,593			604,439
OPERATING EXPENSES:
Operation:
Fuel for power generation		63,952			60,705			139,994			118,292
Purchased power		29,678			97,363			66,859			187,469
Gas purchased for resale		19,916			27,632			90,188			94,528
Deferral of energy costs - electric - net		29,780			(11,695	)		41,576			(3,188	)
Deferral of energy costs - gas - net		3,988			(3,774	)		(363	)		(1,571	)
Other		40,890			34,765			84,905			68,270
Maintenance		8,900			7,864			15,766			14,336
Depreciation and amortization		26,813			22,018			52,498			43,458
Taxes:
Income taxes		4,752			3,952			13,830			13,611
Other than income		5,360			5,198			10,884			10,726
		234,029			244,028			516,137			545,931
OPERATING INCOME		28,833			24,539			65,456			58,508

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		996			5,421			1,593			10,520
Interest accrued on deferred energy		(1,044	)		(627	)		(1,717	)		(1,185	)
Other income		5,792			1,229			8,507			8,964
Other expense		(1,797	)		(2,881	)		(3,788	)		(4,681	)
Income taxes		(1,217	)		(953	)		(1,425	)		(4,527	)
		2,730			2,189			3,170			9,091
Total Income Before Interest Charges		31,563			26,728			68,626			67,599

INTEREST CHARGES:
Long-term debt		16,245			18,578			33,060			37,340
Other		1,430			1,369			3,126			2,991
Allowance for borrowed funds used during construction		(916	)		(4,068	)		(1,500	)		(7,865	)
		16,759			15,879			34,686			32,466

NET INCOME	$	14,804		$	10,849		$	33,940		$	35,133

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

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

	Six Months Ended
	June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	33,940		$	35,133
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		52,498			43,458
Deferred taxes and deferred investment tax credit		33,688			10,537
AFUDC		(1,593	)		(10,520	)
Amortization of energy costs, net of deferrals		45,190			73
Other, net		17,364			2,235
Changes in certain assets and liabilities:
Accounts receivable		60,511			13,330
Materials, supplies and fuel		(1,976	)		(3,437	)
Other current assets		5,172			7,041
Accounts payable		(27,863	)		(11,624	)
Accrued retirement benefits		(11,714	)		826
Other current liabilities		(3,124	)		(4,762	)
Risk management assets and liabilities		868			(431	)
Other deferred assets		(1,886	)		712
Other regulatory assets		(4,095	)		(10,953	)
Other deferred liabilities		(36,070	)		215
Net Cash from Operating Activities		160,910			71,833

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(108,391	)		(119,115	)
Customer advances for construction		(2,178	)		1,672
Contributions in aid of construction		3,752			8,125
Investments and other property - net		(170	)		1,584
Net Cash used by Investing Activities		(106,987	)		(107,734	)

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		160,612			203,000
Retirement of long-term debt		(183,336	)		(125,744	)
Investment by parent company		90,300			20,000
Dividends paid		(123,800	)		(63,333	)
Net Cash from (used by) Financing Activities		(56,224	)		33,923

Net Increase (Decrease) in Cash and Cash Equivalents		(2,301	)		(1,978	)
Beginning Balance in Cash and Cash Equivalents		21,411			23,807
Ending Balance in Cash and Cash Equivalents	$	19,110		$	21,829

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	34,185		$	38,318
Income taxes	$	12		$	19

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, Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, Tuscarora Gas Pipeline Company, which was dissolved in 2008, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Pacific Energy Company, Sierra Water Development Company and Sierra Gas Holding Company. All intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

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

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

Reclassifications

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

Recent Pronouncements

FSP FAS 157-2

In February 2008, the FASB issued FSP FAS 157-2, which deferred the effective date for certain portions of SFAS 157 related to nonrecurring measurements of nonfinancial assets and liabilities. FSP FAS 157-2 was effective for NVE and the Utilities beginning January 1, 2009. The adoption of FSP FAS 157-2 did not have a material impact on the consolidated financial statements of NVE and the Utilities.

SFAS 161

In March 2008, the FASB issued SFAS 161, an amendment of SFAS 133 which is effective for financial statements issued for fiscal years and interim period beginning after November 15, 2008. The purpose of SFAS 161 is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. NVE and the Utilities adopted SFAS 161 beginning January 1, 2009. See Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements.

FSP FAS 107-1 and APB 28-1

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, requiring disclosure of fair values of certain financial instruments in interim financial statements. The provisions of FSP FAS 107-1 and APB 28-1 are effective for NVE and the Utilities as of June 30, 2009. See Note 5, Fair Value of Financial Instruments, of the Condensed Notes to Financial Statements.

FSP FAS 157-4

In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidance on measuring the fair value of financial instruments when markets become inactive and quoted prices may reflect distressed transactions. The provisions of FSP FAS 157-4 are effective for NVE and the Utilities as of June 30, 2009. The adoption of FSP FAS 157-4 did not have an effect on the consolidated financial statements of NVE and the Utilities.

SFAS 165

In May 2009, the FASB issued SFAS 165, which establishes the accounting principles and disclosure requirements for subsequent events. The entity shall disclose the date through which subsequent events have been evaluated, as well as whether that date is the date the financial statements were issued or the date the financial statements were available to be issued. NVE and the Utilities evaluated subsequent events at the time the financial statements were issued, which was August 3, 2009. The statement is effective for NVE and the Utilities as of June 30, 2009.

SFAS 167

In June 2009, the FASB issued SFAS 167, which amends FIN 46 (R). Among the many amendments to FIN 46 (R), the statement amends FIN 46 (R) to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics: a) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. SFAS 167 will be effective for NVE and the Utilities beginning January 1, 2010. NVE and the Utilities are currently evaluating the impact of the adoption of SFAS 167.

SFAS 168

In June 2009, the FASB issued SFAS 168, which replaces SFAS162. SFAS 168 will become the single source of authoritative GAAP, other than guidance put forth by the SEC. All other accounting literature not included in the codification will be considered non-authoritative. SFAS 168 will be effective for NVE and the Utilities for the quarterly period ending September 30, 2009 and will impact the current disclosure of the financial statements since all references to authoritative accounting literature will be references in accordance with SFAS 168.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as defined by SFAS 131) which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative thresholds for separate disclosure.

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

Three months ended	NPC		SPPC		SPPC		SPPC		NVE			NVE
June 30, 2009	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	575,769	$	230,914	$	31,948	$	262,862	$	10		$	838,641

Energy Costs:
Fuel for power generation		140,333		63,952		-		63,952		-			204,285
Purchased power		165,292		29,678		-		29,678		-			194,970
Gas purchased for resale		-		-		19,916		19,916		-			19,916
Deferred energy costs - net		59,809		29,780		3,988		33,768		-			93,577
		365,434		123,410		23,904		147,314		-			512,748

Gross Margin	$	210,335	$	107,504	$	8,044	$	115,548	$	10		$	325,893

Other		68,057						40,890		939			109,886
Maintenance		18,732						8,900		-			27,632
Depreciation and amortization		53,510						26,813		-			80,323
Taxes:
Income taxes (benefit)		1,035						4,752		(1,703	)		4,084
Other than income		8,361						5,360		32			13,753

Operating Income	$	60,640					$	28,833	$	742		$	90,215

Six Months Ended	NPC			SPPC		SPPC			SPPC		NVE			NVE
June 30, 2009	Electric			Electric		Gas			Total		Other			Consolidated

Operating Revenues	$	1,012,298		$	468,652	$	112,941		$	581,593	$	17		$	1,593,908

Energy Costs:
Fuel for power generation		294,395			139,994		-			139,994		-			434,389
Purchased power		253,498			66,859		-			66,859		-			320,357
Gas purchased for resale		-			-		90,188			90,188		-			90,188
Deferred energy costs - net		97,999			41,576		(363	)		41,213		-			139,212
		645,892			248,429		89,825			338,254		-			984,146

Gross Margin	$	366,406		$	220,223	$	23,116		$	243,339	$	17		$	609,762


Other		138,250								84,905		1,408			224,563
Maintenance		46,266								15,766		-			62,032
Depreciation and amortization		105,873								52,498		-			158,371
Taxes:
Income taxes		(17,512	)							13,830		(5,890	)		(9,572	)
Other than income		17,424								10,884		92			28,400

Operating Income	$	76,105							$	65,456	$	4,407		$	145,968

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

Operating Revenues	$	570,223		$	236,415		$	32,152		$	268,567		$	4		$	838,794

Energy Costs:
Fuel for power generation		209,920			60,705			-			60,705			-			270,625
Purchased power		164,087			97,363			-			97,363			-			261,450
Gas purchased for resale		-			-			27,632			27,632			-			27,632
Deferred energy costs - net		(9,691	)		(11,695	)		(3,774	)		(15,469	)		-			(25,160	)
		364,316			146,373			23,858			170,231			-			534,547

Gross Margin	$	205,907		$	90,042		$	8,294		$	98,336		$	4		$	304,247


Other		62,617									34,765			1,265			98,647
Maintenance		13,608									7,864			-			21,472
Depreciation and amortization		42,323									22,018			-			64,341
Taxes:
Income taxes		12,865									3,952			(3,889	)		12,928
Other than income		7,427									5,198			33			12,658

Operating Income	$	67,067								$	24,539		$	2,595		$	94,201

Six Months Ended	NPC		SPPC			SPPC			SPPC			NVE			NVE
June 30, 2008	Electric		Electric			Gas			Total			Other			Consolidated

Operating Revenues	$	1,039,395	$	486,693		$	117,746		$	604,439		$	11		$	1,643,845

Energy Costs:
Fuel for power generation		373,941		118,292			-			118,292			-			492,233
Purchased power		257,837		187,469			-			187,469			-			445,306
Gas purchased for resale		-		-			94,528			94,528			-			94,528
Deferred energy costs - net		36,084		(3,188	)		(1,571	)		(4,759	)		-			31,325
		667,862		302,573			92,957			395,530			-			1,063,392

Gross Margin	$	371,533	$	184,120		$	24,789		$	208,909		$	11		$	580,453


Other		119,712								68,270			2,340			190,322
Maintenance		30,258								14,336			-			44,594
Depreciation and amortization		82,953								43,458			-			126,411
Taxes:
Income taxes		14,997								13,611			(7,061	)		21,547
Other than income		15,749								10,726			90			26,565

Operating Income	$	107,864							$	58,508		$	4,642		$	171,014

NOTE 3. REGULATORY ACTIONS

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

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

Description	NPC Electric				SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2009 DEAA	$	77,473		(1)	$	(19,813	)	$	(8,733	)	$	48,927
2009 Amortization		8				287			-			295
2009 Deferred Energy Costs/Over Collections (2)		(79,176	)			(45,251	)		122			(124,305	)
Nevada Deferred Energy Balance at June 30, 2009 - Subtotal	$	(1,695	)		$	(64,777	)	$	(8,611	)	$	(75,083	)
Cumulative CPUC balance		-				1,541			-			1,541
Western Energy Crisis Rate Case (effective 6/07, 3 years)		30,648				-			-			30,648
Reinstatement of deferred energy (effective 6/07, 10 years)		155,898				-			-			155,898

Total	$	184,851			$	(63,236	)	$	(8,611	)	$	113,004

Current Assets
Deferred energy costs – electric		39,743				-			-			39,743
Deferred Assets
Deferred energy costs – electric		145,108				-			-			145,108
Other Current Liabilities		-				(63,236	)		(8,611	)		(71,847	)
Total	$	184,851			$	(63,236	)	$	(8,611	)	$	113,004

(1)	Reflects ordered adjustments.
(2)	These costs/over collections are to be requested in February 2010 DEAA filings.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Ely Energy Center

On February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $76.4 million as of June 30, 2009. Management expects full recovery of the amounts expended through June 30, 2009. Future plans with the EEC will be addressed through the Utilities' IRP processes. In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC. Simultaneously, the Utilities filed a new UEPA application for the construction of the ON Line project.

Nevada Power Company

NPC 2009 Nevada IRP

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

NPC 2009 Deferred Energy Rate Case

In February 2009, NPC filed an application to create a new DEAA rate. In this application, NPC requests to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs. The new DEAA rate, if approved, will be effective October 1, 2009.

Sierra Pacific Power Company

SPPC Nevada Gas DEAA

In February 2009, SPPC filed an application to create a new gas DEAA rate for Nevada customers. In this application, SPPC requests to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs. The new DEAA rate, if approved, will be effective October 1, 2009.

SPPC Nevada Electric DEAA

In February 2009, SPPC filed an application to create a new electric DEAA rate for Nevada customers. In this application, SPPC requests to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs. The new DEAA rate, if approved, will be effective October 1, 2009.

SPPC California GRC

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

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

If approved, the new rates will be effective on November 1, 2009.

Settled Regulatory Actions

Nevada Power Company

NPC 2008 GRC

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

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

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

Mohave Generating Station

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

NOTE 4. LONG-TERM DEBT

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

	NPC			SPPC		NVE Holding Co. and Other Subs.		NVE Consolidated

2009	$	3,668		$	-	$	-	$	3,668
2010		123,004			171,000		-		294,004
2011		369,924			-		-		369,924
2012		136,449			100,000		63,670		300,119
2013		7,146			250,000		-		257,146
		640,191			521,000		63,670		1,224,861
Thereafter		3,093,359			843,500		421,539		4,358,398
		3,733,550			1,364,500		485,209		5,583,259
Unamortized Premium (Discount) Amount		(12,449	)		9,492		582		(2,375	)
Total	$	3,721,101		$	1,373,992	$	485,791	$	5,580,884

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

Nevada Power Company

Revolving Credit Facilities

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

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

General and Refunding Mortgage Notes, Series V

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

General and Refunding Mortgage Notes, Series U

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

Sierra Pacific Power Company

Revolving Credit Facility

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

Conversions

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

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

NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The June 30, 2009, carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments.

The total fair value of NVE’s consolidated long-term debt at June 30, 2009, is estimated to be $5.5 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $4.9 billion as of December 31, 2008.

The total fair value of NPC’s consolidated long-term debt at June 30, 2009, is estimated to be $3.7 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $3.1 billion at December 31, 2008.

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

NOTE 6. DERIVATIVES AND HEDGING ACTIVITIES

NVE, SPPC and NPC apply SFAS 133, as amended by SFAS 138, SFAS 149, SFAS 155, SFAS 157 and SFAS 161. As amended, SFAS 133 establishes accounting and reporting standards for derivatives instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value.

Adoption of SFAS 161

Effective January 1, 2009, NVE and the Utilities’ adopted SFAS 161, which is intended to enhance the current disclosure framework in SFAS 133. SFAS 161 requires the objectives for using derivative instruments be disclosed in terms of underlying risk and accounting. SFAS 161 requires NVE and the Utilities to distinguish between instruments used for risk management and instruments used for other purposes. SFAS 161 requires disclosing the fair values of derivative instruments and their gains and losses for the period, providing more information about credit-risk related contingent features and describing the volume of their derivative activity.

Commodity Risk

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

Credit Risk Contingent Features

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s, Fitch, and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities’ Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of June 30, 2009, the maximum amount of collateral NPC and SPPC would be required to post under these agreements is approximately $174.0 million and $76.5 million, respectively, based on mark-to-market liability values, which are substantially based on quoted market prices. Of this amount, approximately $105.5 million and $40.5 million, respectively, would be required if NPC and SPPC are downgraded one level and additional amounts of approximately $68.5 million and $36.0 million would be required respectively if NPC and SPPC are downgraded two levels.

Determination of Fair Value

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps and options. Total risk management assets below do not include option premiums which are not considered a derivative asset. Option premiums upon settlement are recorded in fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism. Option premium amounts included in risk management assets for NVE, NPC and SPPC were as follows (dollars in millions):

	Option Premiums
	June 30, 2009						December 31, 2008
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	16.6	$	13.4	$	3.2	$	13.3	$	9.7	$	3.6
Non-Current		4.8		3.9		0.9		5.6		4.2		1.4
Total	$	21.4	$	17.3	$	4.1	$	18.9	$	13.9	$	5.0

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

The following table shows the fair value of the open derivative positions recorded on the consolidated balance sheets of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS 133. Due to deferred energy accounting treatment under which the Utilities’ operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses through income (dollars in millions):

Commodity Contracts	June 30, 2009 Fair Value Level 2 (as defined by SFAS 157)									December 31, 2008 Fair Value Level 2 (as defined by SFAS 157)
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current	$	2.8		$	2.2		$	0.6		$	2.8		$	2.0		$	0.8
Risk management assets- noncurrent		6.9			5.3			1.6			4.4			3.2			1.2
Total risk management assets		9.7			7.5			2.2			7.2			5.2			2.0

Risk management liabilities- current		305.9			219.1			86.8			313.8			222.9			90.9
Risk management liabilities- noncurrent		14.4			10.9			3.5			53.4			35.2			18.2
Total risk management liabilities		320.3			230.0			90.3			367.2			258.1			109.1

Risk management regulatory assets/liabilities – net (1)	$	(310.6	)	$	(222.5	)	$	(88.1	)	$	(360.0	)	$	(252.9	)	$	(107.1	)

(1)

When amount is negative it represents a Risk Management Regulatory Asset, when positive it represents a Risk Management Regulatory Liability. Under SFAS 161, NVE and the Utilities would have recorded losses for the three months ended March 31, 2009 of $ (81.7) million, $ (69.9) million, and $ (11.8) million, respectively and gains for the three months ended June 30, 2009 of $131.1 million, $100.3 million, and $30.8 million, respectively. For the six months ended June 30, 2009, NVE and the Utilities would have recorded a cumulative gain of $49.4 million, $30.4 million, and $19.0 million, respectively. However, in accordance with SFAS 71, NVE and the Utilities deferred these gains and losses, which are included in the Risk Management Regulatory Assets/Liabilities amounts above.

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in forward commodity prices. The decrease in risk management liabilities as of June 30, 2009, as compared to December 31, 2008, is mainly due to less disparity between the derivative positions held by the Utilities to hedge energy price risk relative to natural gas prices at June 30, 2009.

The following table shows the commodity volume of our natural gas contracts (amounts in millions):

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

Commodity volume assets- current		12.1		9.8		2.3		1.2		1.0		0 .2
Commodity volume assets- noncurrent		25.9		19.9		6.0		1.1		1.0		0 .1
Total commodity volume of assets		38.0		29.7		8.3		2.3		2.0		0.3

Commodity volume liabilities- current		118.7		87.7		31.0		119.9		86.7		33.2
Commodity volume liabilities- noncurrent		15.3		11.8		3.5		40.6		28.6		12.0
Total commodity volume of liabilities		134.0		99.5		34.5		160.5		115.3		45.2

NOTE 7. COMMITMENTS AND CONTINGENCIES

Environmental Contingencies

Nevada Power Company

NEICO

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

Sierra Pacific Power Company

Valmy Generating Station

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

Other Environmental Matters

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

Litigation Contingencies

Nevada Power Company

Lawsuit Against Natural Gas Providers

In April 2003, NVE (originally filed under the corporate name of SPR) and NPC filed a complaint in the U.S. District Court for the District of Nevada (“District Court”) against several natural gas providers and traders. In July 2003, NVE and NPC filed a First Amended Complaint. A Second Amended Complaint was filed in June 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company (“El Paso”); (2) Dynegy Marketing and Trade (“Dynegy”); and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric (“Sempra”). On December 13, 2005, the District Court dismissed NVE and NPC’s claims. NVE and NPC appealed this decision to the Ninth Circuit. Subsequently, NVE abandoned its appeal and the matter proceeded only with respect to NPC. In September 2007, the Ninth Circuit reversed the District Court’s order. In November 2007, the Ninth Circuit denied the gas providers and traders’ petition for rehearing. The Ninth Circuit has remanded the case to the District Court for further proceedings. In January 2008, the defendants filed motions to dismiss, to which NPC responded in February 2008. In June 2008, NPC’s claims survived the defendant’s filed motions to dismiss. On December 9, 2008, NPC settled with Sempra for an immaterial amount. In June, 2009, NPC reached settlement agreements with both El Paso and Dynegy. Any disputes between the parties have now been resolved and all claims have been dismissed.

Peabody Western Coal Company

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

Royalty Claim

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

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

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo and Mohave Generating Stations. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo and Mohave Generating Stations by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action was stayed since October 5, 2004 until March, 2008 when the U.S. District Court referred pending discovery related motions to a Magistrate judge. Those discovery motions have now been resolved and the Court ordered completion of factual discovery by February 11, 2010.

Sierra Pacific Power Company

Farad Dam

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

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

Other Legal Matters

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

NOTE 8. EARNINGS PER SHARE (NVE)

The difference, 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. Due to the net loss for the six months ended June 30, 2009, these items are anti-dilutive and diluted EPS for the period is computed using the weighted average number of shares outstanding before dilution.


		Three months ended June 30,				Six months ended June 30,
		2009		2008		2009			2008
Basic EPS
Numerator ($000)

	Net income (loss)	$	18,383	$	36,134	$	(3,861	)	$	60,192

Denominator
	Weighted average number of common shares outstanding		234,474,727		233,992,721		234,403,282			233,914,046

Per Share Amounts

	Net income (loss) per share - basic	$	0.08	$	0.15	$	(0.02	)	$	0.26

Diluted EPS
Numerator ($000)

	Net income (loss)	$	18,383	$	36,134	$	(3,861	)	$	60,192

Denominator (1)
	Weighted average number of shares outstanding before dilution		234,474,727		233,992,721		234,403,282			233,914,046
	Stock options		18,979		57,533		-			59,142
	Non-Employee Director stock plan		95,878		56,987		-			56,650
	Employee stock purchase plan		5,102		871		-			436
	Restricted Shares		10,026		5,247		-			3,279
	Performance Shares		484,481		406,203		-			386,783
			235,089,193		234,519,562		234,403,282			234,420,336

Per Share Amounts

	Net income (loss) per share - diluted	$	0.08	$	0.15	$	(0.02	)	$	0.26

(1)

The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan for the three and six months ended June 30, 2009 and 2008, due to conversion prices being higher than market prices for all periods. Under this plan for the three and six months ended June 30, 2009, 731,505 and 902,092 shares, respectively, would be included and 972,761 and 941,278 shares, respectively, would be included for the three and six months ended June 20, 2008, if the conditions for conversions were met.

NOTE 9. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

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

NV Energy, Inc., consolidated
	Pension Benefits						Other Postretirement Benefits
	For the three months ended June 30,						For the three months ended June 30,
	2009			2008			2009			2008

Service cost	$	4,709		$	5,247		$	577		$	716
Interest cost		11,036			10,675			2,637			3,148
Expected return on plan assets		(9,290	)		(11,463	)		(1,508	)		(2,144	)
Amortization of prior service cost		(448	)		(118	)		(171	)		234
Amortization of net (gain)/loss		6,894			1,981			1,273			855
Settlement (gain)/loss		-			-			84			-

Net periodic benefit cost	$	12,901		$	6,322		$	2,892		$	2,809


	Pension Benefits						Other Postretirement Benefits
	For the six months ended June 30,						For the six months ended June 30,
		2009			2008			2009			2008

Service cost	$	9,419		$	11,270		$	1,155		$	1,281
Interest cost		22,073			21,465			5,275			5,366
Expected return on plan assets		(18,580	)		(24,124	)		(3,016	)		(4,175	)
Amortization of prior service cost		(897	)		290			(343	)		(514	)
Amortization of net (gain)/loss		13,787			2,752			2,545			1,744
Settlement (gain)/loss		-			-			169			-

Net periodic benefit cost	$	25,802		$	11,653		$	5,785		$	3,702

Nevada Power Company
	Pension Benefits						Other Postretirement Benefits
	For the three months ended June 30,						For the three months ended June 30,
	2009			2008			2009			2008

Service cost	$	2,393		$	3,062		$	310		$	313
Interest cost		5,270			5,257			607			707
Expected return on plan assets		(4,462	)		(5,496	)		(509	)		(671	)
Amortization of prior service cost		(433	)		1			289			399
Amortization of net (gain)/loss		3,298			981			287			186
Settlement (gain)/loss		-			-			19			-

Net periodic benefit cost	$	6,066		$	3,805		$	1,003		$	934


	Pension Benefits						Other Postretirement Benefits
	For the six months ended June 30,						For the six months ended June 30,
		2009			2008			2009			2008

Service cost	$	4,786		$	6,612		$	621		$	608
Interest cost		10,539			10,610			1,213			1,262
Expected return on plan assets		(8,924	)		(11,562	)		(1,019	)		(1,351	)
Amortization of prior service cost		(866	)		363			579			579
Amortization of net (gain)/loss		6,596			1,357			574			404
Settlement (gain)/loss		-			-			38			-

Net periodic benefit cost	$	12,131		$	7,380		$	2,006		$	1,502

Sierra Pacific Power Company
	Pension Benefits						Other Postretirement Benefits
	For the three months ended June 30,						For the three months ended June 30,
	2009			2008			2009			2008

Service cost	$	2,061		$	1,939		$	251		$	384
Interest cost		5,471			5,063			2,014			2,401
Expected return on plan assets		(4,580	)		(5,668	)		(977	)		(1,438	)
Amortization of prior service cost		(26	)		(64	)		(465	)		(169	)
Amortization of net (gain)/loss		3,425			920			978			659
Settlement (gain)/loss		-			-			65			-

Net periodic benefit cost	$	6,351		$	2,190		$	1,866		$	1,837


	Pension Benefits						Other Postretirement Benefits
	For the six months ended June 30,						For the six months ended June 30,
		2009			2008			2009			2008

Service cost	$	4,122		$	4,117		$	503		$	638
Interest cost		10,942			10,149			4,027			4,027
Expected return on plan assets		(9,160	)		(11,933	)		(1,954	)		(2,756	)
Amortization of prior service cost		(52	)		(12	)		(929	)		(1,101	)
Amortization of net (gain)/loss		6,851			1,256			1,956			1,317
Settlement (gain)/loss		-			-			130			-

Net periodic benefit cost	$	12,703		$	3,577		$	3,733		$	2,125

In 2008, in accordance with SFAS 158, NVE, NPC and SPPC recorded additional pension costs relating to the elimination of the early measurement date to retained earnings of $5.3 million, $3.6 million and $1.4 million, respectively, before taxes. Also, in 2008, in accordance with SFAS 158, NVE, NPC and SPPC recorded additional post retirement benefit costs relating to the elimination of the early measurement date, to retained earnings of $1.0 million, $0.6 million and $0.4 million, respectively, before taxes. These amounts represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007.

For the six months ended June 30, 2009, the company made contributions to the pension plan totaling $40 million, with $25.5 million allocated to the 2008 plan year and the remainder to the 2009 plan year. At the present time it is anticipated that there will be further contributions made to both the pension and other postretirement benefits plans in 2009; however, the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution.

NOTE 10. DIVIDENDS

On February 5, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share which was paid in March 2009 to common shareholders of record on March 3, 2009. On April 30, 2008, NVE’s BOD declared a quarterly cash dividend of $0.10 per share to common shareholders of record on June 2, 2009, which was paid on June 17, 2009.

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

During the six months ended June 30, 2009, NPC and SPPC paid dividends to NVE of $37 million and $123.8 million, respectively. On July 31, 2009, NPC and SPPC paid dividends to NVE of $25 million and $5 million, respectively.

NOTE 11. INCOME TAXES

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

In April 2009, NVE and the Utilities received notice from the IRS approving the Application. Accordingly, during the second quarter of 2009, NVE, NPC and SPPC recorded reductions to their unrecognized tax benefits for the repair positions taken in the prior period of approximately $55.5 million, $32.0 million, and $32.3 million, respectively. No additional material changes in the FIN 48 reserves are anticipated in the next twelve months.

NOTE 12. ASSETS HELD FOR SALE

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

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

Assets	June 30, 2009		December 31, 2008

Utility Plant in Service	$	186.2	$	183.2

Less: Accumulated depreciation		57.9		56.0
Utility Plant in Service, net		128.3		127.2

CWIP		6.7		5.5
Other current assets		5.4		6.8
Deferred Charges		2.6		3.0

Assets Held for Sale	$	143.0	$	142.5

Liabilities

Deferred Credits and Other Liabilities	$	24.7	$	24.1

Liabilities Held for Sale	$	24.7	$	24.1

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

Forward-Looking Statements and Risk Factors

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

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

(1)

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

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

(3)

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

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

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

(6)

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

(7)

whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands (for example, due to unseasonably hot weather), physical availability, sharp increases in the prices for fuel (including increases in long term transportation costs) and/or power, or a ratings downgrade;

(8)

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

(9)	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;

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

(11)

unfavorable or untimely rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas costs recorded by SPPC for its gas distribution business;

(12)

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

(13)

the discretion of NVE's BOD regarding NVE's future common stock dividends based on the BOD periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in NVE's and the Utilities' agreements;

(14)	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;

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

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

(17)

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

(18)	employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce; and

(19)	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

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

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;

•	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•	may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

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

EXECUTIVE OVERVIEW

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

●	For each of NVE, NPC and SPPC:

	§	Results of Operations

	§	Analysis of Cash Flows

	§	Liquidity and Capital Resources

●	Regulatory Proceedings (Utilities)

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

NVE recognized net income of $18.4 million for the three months ended June 30, 2009 compared to net income of $36.1 million for the same period in 2008. NVE incurred a net loss of $3.9 million for the six months ended June 30, 2009 compared to net income of $60.2 million for the same period in 2008. Consolidated gross margin increased by $21.6 million and $29.3 million for the three months and six months ended, respectively, primarily due to increased rates as a result of SPPC’s 2007 GRC, effective July 1, 2008. Earnings decreased primarily due to increased other operating and maintenance expenses, depreciation and interest charges, some of which are costs related to the purchase of the Higgins Generating Station and the construction of the Clark Peaking Units, which were not included in rates prior to July 1, 2009, and lower revenues, as a result of milder weather. Other Income/Expense items which contributed to the change in earnings are discussed in NPC’s and SPPC’s respective Results of Operations for more details on the change in earnings.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. As of July 3 1 , 2009, the Utilities have not reached their system peaks as forecasted; however, NPC's 2009 system peak to date has exceeded its 2008 system peak. The variations in energy usage by the Utilities’ customers due to varying weather and other energy usage patterns necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2009 Current Matters

The economy in Nevada has been adversely affected by the recession facing the U.S. and the global economy, resulting in decelerated customer growth compared to prior years when Nevada was experiencing high customer growth. Tourism and gaming remain southern Nevada’s leading industries, driving construction activity, the housing market and employment in the region, and together comprising one of NPC’s largest classes of customers. Management continues to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas. The hotel/motel occupancy rate has decreased approximately 5.3% as of May 2009 from a year ago. The expected room growth rate for 2009 is 6.2%, concentrated primarily in Project City Center, which is developed and jointly owned by MGM Mirage, and 4.9% for 2010. Gaming properties in southern Nevada are experiencing financial problems, including difficulties meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases. Additionally, the unemployment rate in Nevada is currently at 11.0% compared to 5.8% in 2008. Other economic conditions affecting Nevada include the national decrease in real estate market activity which makes it more difficult for individuals and businesses to sell their properties in order to relocate to Nevada. These factors, among other items, are considered and evaluated by management in assessing load forecast.

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

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

Upon evaluation of the factors above, NVE and the Utilities have reduced estimated cash requirements, as reported in the 2008 Form 10-K, for capital expenditures by approximately $145 million to $170 million for 2009 for total estimated cash requirements of $775 million to $750 million for the current year. The current recession, as well as recent volatility in the global credit and financial markets, has created an unprecedented level of uncertainty regarding future business conditions. While management expects to maintain this process of continual re-evaluation for the foreseeable future, it is not possible to predict how long the economic recession will continue or what its long-term effect will be on the economy in general or on our financial position, cash flows or results of operations in particular.

2009 and Beyond

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

Energy Efficiency and Conservation Programs

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

The Utilities are planning to invest between $45 million and $60 million in DSM programs in 2009. The final amount will be determined by numerous factors, such as the economy, the impact of federal government stimulus legislation, performance of existing and new programs and many other factors.

Purchase and Development of Renewable Energy Projects

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

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

Expansion of Traditional Generating and Transmission Capacity

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

Management of Energy Risk

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

Management of Environmental Matters

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

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

Management of Regulatory Filings

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

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

Further Broaden Access to Capital

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

Commodity prices and the amount of capital required for construction projects are projected to be significantly lower for the remainder of 2009 compared to 2008. As a result, for the remainder of 2009, the Utilities believe they will be able to meet such financial obligations with a combination of internally generated funds and the use of the Utilities’ revolving credit facilities. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, the Utilities may need to issue additional debt to support their operating costs or further delay capital expenditures, and NVE may need to issue additional equity securities. As such, maintaining sufficient liquidity through the use of the Utilities’ revolving credit facilities and maintaining our ability to issue new debt or equity securities on favorable terms continues to be a significant focus in 2009.

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 $19.3 million and $20.9 million of interest costs for the six months ended June 30, 2009 and 2008 respectively.

As of June 30, 2009 NPC had paid $37.0 million in dividends to NVE and SPPC had paid $123.8 million in dividends to NVE. As of June 30, 2009, NVE contributed capital to SPPC of $90.3 million during 2009.

Other Subsidiaries

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

ANALYSIS OF CASH FLOWS

Cash flows increased during the six months ended June 30, 2009 compared to the same period in 2008 primarily due to an increase in cash from financing activities and to a lesser extent cash from operating activities partially offset by an increase in cash used for investing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to an over collection of deferred energy revenues in excess of fuel costs and an increase in revenues as a result of SPPC’s 2007 GRC. Also contributing to the increase in cash from operating activities was a reduction in spending for regulatory activities, and settlement of outstanding litigation. These increases were partially offset by the following:

•	lower revenues as a result of milder weather and a change in customer usage patterns, as further discussed below under NPC's and SPPC's Results of Operations;
•	an increase in costs for operations and maintenance costs for generating facilities, some of which will be included in rates as of July 1, 2009 as a result of NPC’s 2008 GRC as further discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements;
•	funding of approximately $40 million for pension plans;
•	higher interest costs;
•	higher balances for fuel and purchased power costs at year end December 31, 2008, that were subsequently paid in 2009; and
•	prepaid transmission revenues received in 2008.

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

Cash From Financing Activities. Cash from financing activities increased primarily due to the issuance of approximately $625 million in new debt, partially offset by payments on the revolving credit facility and an increase in dividends to common shareholders.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

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

As of June 30, 2009, NVE, NPC and SPPC had cash on hand of approximately $21.5 million, $35.9 million, and $19.1 million, respectively. NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, the Utilities may use the combined balance under their revolving credit facilities of $691 million, as of June 30, 2009 in order to meet their liquidity needs. Alternatively, depending on the usage of the Utilities’ revolving credit facilities, NVE and the Utilities may issue long-term debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. NVE and the Utilities anticipate with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the Utilities’ revolving credit facilities, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity, NVE and the Utilities may be required to further delay capital expenditures, re-finance debt or issue equity.

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

NVE and the Utilities do not have significant debt maturities in 2009 or 2010 other than their revolving credit facilities. As of July 31, 2009, NPC and SPPC had approximately $130.8 million and $189.3 million, respectively outstanding on their revolving credit facilities including letters of credit. The Utilities’ long-term credit facilities expire in November 2010, and NPC’s Supplemental Revolving Credit Facility expires in January 2010.

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

NVE (stand-alone) has approximately $18.9 million of debt service obligations remaining for 2009, which it intends to fund through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries below).

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

Factors Affecting Liquidity

Effect of Holding Company Structure

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

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by 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 June 30, 2009, NVE, NPC, SPPC and their subsidiaries had approximately $5.6 billion of debt and other obligations outstanding, consisting of approximately $3.7 billion of debt at NPC, approximately $1.4 billion of debt at SPPC and approximately $485 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

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

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

As of June 30, 2009, NPC and SPPC paid dividends to NVE of $37 million and $123.8 million, respectively. On July 31, 2009, NPC and SPPC paid dividends of $25.0 million and $5.0 million, respectively, to NVE. As of June 30, 2009, NVE contributed $90.3 million to SPPC during 2009.

Credit Ratings

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

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

*Investment grade

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

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

NV Energy, Inc.

Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends.

Under these restrictions, NVE (holding company), NPC and SPPC are permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities without having to satisfy any incurrence or maintenance test. As of June 30, 2009, NPC had approximately $115 million borrowed and $18.3 million of letters of credit outstanding and SPPC had approximately $171 million borrowed and $16.2 million in letters of credit outstanding against the credit facilities, leaving a combined availability of approximately $179.5 million under this restriction.

The holding company’s debt restrictions also permit the Utilities to exceed the combined total of $500 million in indebtedness and letters of credit, and/or permit the issuance of additional long term debt by NVE and the Utilities so long as, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1 (CFFC ratio). Under the CFFC ratio and based upon estimated interest expense, as of June 30, 2009, NVE (consolidated) would be permitted to utilize all of the remaining availability of approximately $691 million under the Utilities’ revolving credit facilities. Alternatively, NVE, NPC and SPPC could issue additional long term debt in an aggregate amount of approximately $197 million. At this time, the Utilities would likely utilize the revolving credit facilities for liquidity needs. The Utilities continually evaluate such factors in determining the best means of satisfying their liquidity requirements.

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

Nevada Power Company

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt. Under the most restrictive of these factors, as discussed below, and based on estimated interest expense, as of June 30, 2009, NPC has the ability to utilize all of the remaining balance of $546 million under its revolving credit facilities or, alternatively, to issue additional long term debt of up to $197 million.

On February 4, 2009, the PUCN approved NPC’s request for financing authority to issue up to $1.25 billion of long-term debt securities over a two-year period ending December 31, 2010, ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and authority to refinance up to approximately $471 million of long-term debt securities.

NPC's $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2009, NPC was in compliance with these covenants. Based upon estimated interest expense, in order to maintain compliance with these covenants, NPC would be able to utilize all of the available balance under its revolving credit facilities of $546 million. Alternatively, this test would allow NPC to incur $541 million of additional long-term debt.

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

Furthermore, as discussed in NVE’s Ability to Issue Debt, NPC is subject to NVE’s cap on additional consolidated indebtedness. Although NVE’s cap would, as of June 30, 2009, permit the Utilities to utilize all the remaining balance of $691 million available under the their revolving credit facilities, the NVE cap would, alternatively, limit NVE, NPC and SPPC to issuing not more than an aggregate of $197 million of additional long term debt. As a result, with respect to use of its revolving credit facilities, NPC may utilize all of the available balance of $546 million; however, NPC’s ability to issue additional long term debt is effectively restricted by NVE’s covenant restrictions, which limit the issuance of long-term debt to $197 million on a consolidated basis. Moreover, NPC’s ability to issue additional long term debt may be further reduced to the extent that NVE and/or SPPC issue additional long-term debt. At this time it is likely that NPC would rely on its revolving credit facilities for its liquidity needs.

Ability to Issue General and Refunding Mortgage Securities

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

NPC's Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of June 30, 2009, $4 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $610 million of General and Refunding Mortgage Securities as of June 30, 2009. That amount is determined on the basis of:

1.	70% of net utility property additions;
2.	the principal amount of retired General and Refunding Mortgage Securities; and/or
3.	the principal amount of first mortgage bonds retired after October 2001.

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

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

Sierra Pacific Power Company

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt. Under the most restrictive of these factors, as discussed below, and based on estimated interest expense, as of June 30, 2009, SPPC has the ability to utilize all of the remaining balance of $145 million under its revolving credit facility or, alternatively, to issue additional long-term debt of up to $197 million.

As of June 30, 2009, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

SPPC's $332 million Amended and Restated Revolving Credit Agreement dated November 2005, contains two financial maintenance covenants. The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2009, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC would be able to utilize all of the available balance under its revolving credit facility of $145 million. Alternatively, this test would allow SPPC to incur $672 million of additional long-term debt.

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

Furthermore, as discussed in NVE’s Ability to Issue Debt, SPPC is subject to NVE’s cap on additional consolidated indebtedness. Although NVE’s cap would, as of June 30, 2009, permit the Utilities to utilize all of the remaining balance of $691 million available under their revolving credit facilities, the NVE cap would, alternatively, limit NVE, NPC and SPPC to issuing not more than an aggregate $197 million of additional long-term debt. As a result, with respect to use of its revolving credit facility SPPC may utilize all of the available balance of $145 million; however SPPC’s ability to issue additional long-term debt is effectively restricted by NVE’s covenant restrictions which limits the issuance of long-term debt to $197 million on a consolidated basis. Moreover, SPPC’s ability to issue additional long-term debt may be further reduced to the extent that NVE and or NPC issue additional long-term debt. At this time it is likely that SPPC would rely on its revolving credit facilities for its liquidity needs.

Ability to Issue General and Refunding Mortgage Securities

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

SPPC's Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of June 30, 2009, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $624 million of General and Refunding Mortgage Securities as of June 30, 2009. That amount is determined on the basis of:

1.	70% of net utility property additions;
2.	the principal amount of retired General and Refunding Mortgage Securities; and/or
3.	the principal amount of first mortgage bonds retired after October 2001.

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

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

Cross Default Provisions

None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

Energy Supplier Matters

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

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC and SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of June 30, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $78.9 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

Gas Supplier Matters

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

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

Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of June 30, 2009, the maximum amount of collateral the Utilities would be required to post under these agreements is approximately $242.7 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $141.0 million would be required if the Utilities are downgraded one level and an additional amount of approximately $101.7 million would be required if the Utilities are downgraded two levels.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $12.5 million during the three months ended June 30, 2009 compared to net income of $33.2 million for the same period in 2008. During the six months ended June 30, 2009, NPC incurred a net loss of approximately $22.7 million compared to net income of approximately $41.1 million for the same period in 2008.

During the six months ended June 30, 2009, NPC paid $37.0 million in dividends to NVE. On July 31, 2009, NPC paid $25.0 million in dividends to NVE.

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

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

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

	Three Months Ended June 30,								Six Months Ended June 30,
						Change from							Change from
	2009		2008			Prior Year %			2009		2008		Prior Year %
Operating Revenues:
Electric	$	575,769	$	570,223			1.0	%	$	1,012,298	$	1,039,395		-2.6	%


Energy Costs:
Fuel for power generation		140,333		209,920			-33.1	%		294,395		373,941		-21.3	%
Purchased power		165,292		164,087			0.7	%		253,498		257,837		-1.7	%
Deferral of energy costs-net		59,809		(9,691	)		-717.2	%		97,999		36,084		171.6	%
	$	365,434	$	364,316			0.3	%	$	645,892	$	667,862		-3.3	%


Gross Margin	$	210,335	$	205,907			2.2	%	$	366,406	$	371,533		-1.4	%

Gross margin increased for the three months ended June 30, 2009 compared to the same period in 2008 primarily due to an increase in residential customer usage as a result of warmer weather, increased revenues associated with renewable energy programs, and a slight increase in average customer growth. Partially offsetting the increase was a decrease in usage by commercial and industrial customers, the termination of various transmission service agreements and a change in customer usage patterns.

Gross margin decreased for the six months ended June 30, 2009 compared to the same period in 2008 primarily due to milder weather, decreased customer usage by the commercial and industrial customers, the termination of various transmission service agreements, and a change in customer usage patterns. Partially offsetting the decrease were increased revenues associated with renewable energy programs and a slight increase in average customer growth.

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

Electric Operating Revenues

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %
Electric Operating Revenues:
Residential	$	263,556	$	245,810		7.2	%	$	454,926	$	451,188		0.8	%
Commercial		120,297		123,947		- 2.9	%		217,091		228,459		-5.0	%
Industrial		171,895		176,778		- 2.8	%		299,934		309,789		-3.2	%
Retail revenues		555,748		546,535		1.7	%		971,951		989,436		-1.8	%
Other		20,021		23,688		-15.5	%		40,347		49,959		-19.2	%
Total Revenues	$	575,769	$	570,223		1.0	%	$	1,012,298	$	1,039,395		-2.6	%

Retail sales in thousands
Of MWhs		5,309		5,245		1.2	%		9,429		9,539		-1.2	%

Average retail revenue per MWh	$	104.68	$	104.20		0.5	%	$	103.08	$	103.72		-0.6	%

NPC’s retail revenues increased for the three months ended June 30, 2009 as compared to the same period in 2008.

•

Residential retail revenues increased primarily due to an increase in customer usage due to hotter than normal weather in May, slightly offset by lower temperatures in June. Also contributing to the increase in residential retail revenues was revenue associated with renewable energy projects and a slight increase to customer count of 0.1%. These increases in residential retail revenues were partially offset by decreased rates as a result of NPC’s various BTER quarterly cases and deferred energy cases (See Note 3, Regulatory Actions of the Notes to the Financial Statements).

•

Commercial and Industrial retail revenues decreased primarily due to lower customer usage resulting from cooler temperatures in June 2009 combined with higher summer BTGR rates. Between June 1st and September 30th many of these customers are charged a tiered time-of-use BTGR rate and additional demand charges based on usage during peak, mid-peak, and low demand periods of the day with significantly higher BTGR rates during peak and mid-peak times of use. As a result of cooler weather in June, usage was significantly lower than the prior year and many commercial and industrial customers avoided the higher charges. This decrease was slightly offset by increased usage in May at lower non-summer rates due to hotter temperatures. Decreased retail rates as a result of NPC’s various BTER quarterly cases and deferred energy cases also contributed to the decrease. (See Note 3, Regulatory Actions of the Notes to the Financial Statements).

The average number of commercial and industrial customers increased by 1.1% and 2.4%, respectively.

NPC’s retail revenues decreased for the six months ended June 30, 2009 compared to the same period in 2008 due to the items noted above, as well as, a decrease in customer usage largely due to milder winter weather in the first quarter of 2009 and, to a lesser extent, changes in customer usage patterns, as well as a decrease in rates. The average number of residential, commercial and industrial customers increased by 0.4%, 0.8% and 2.8%, respectively.

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

Energy Costs

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

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

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Energy Costs	$	305,625	$	374,007		-18.3	%	$	547,893	$	631,778		-13.3	%
Total System Demand		5,695		5,617		1.4	%		10,037		10,149		-1.1	%
Average cost per MWh	$	53.67	$	66.58		-19.4	%	$	54.59	$	62.25		-12.3	%

Energy costs and the average cost per MWh decreased for the three months ended June 30, 2009 compared to the same period in 2008 while total system demand increased slightly. Energy costs and the average cost per MWh decreased primarily due to a decline in natural gas prices and an increase in self generation which was more economical than purchased power, partially offset by an increase in the settlement costs for hedging instruments. For the three months ended June 30, 2009 NPC self generated approximately 72% of total system demand compared to approximately 67% for the same period in 2008. The slight increase in total system demand was primarily due to hotter weather during May 2009.

Energy costs, total system demand and the average cost per MWh decreased for the six months ended June 30, 2009 compared to the same period in 2008. Energy costs and the average cost per MWh decreased primarily due to a decline in natural gas prices and an increase in self generation which was more economical than purchased power, partially offset by an increase in the settlement costs for hedging instruments. For the six months ended June 30, 2009 NPC self generated approximately 77% of total system demand compared to approximately 70% for the same period in 2008. The decrease in demand for the six month period was primarily due to a decrease in customer usage as a result of milder weather and a change in customer usage patterns.

Fuel For Power Generation

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Fuel for power generation	$	140,333	$	209,920		-33.1	%	$	294,395	$	373,941		-21.3	%

Thousands of MWhs generated		4,083		3,784		7.9	%		7,690		7,120		8.0	%
Average cost per MWh of
generated power	$	34.37	$	55.48		-38.1	%	$	38.28	$	52.52		-27.1	%

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

Purchased Power

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Purchased Power	$	165,292	$	164,087		0.7	%	$	253,498	$	257,837		-1.7	%

Purchased Power in thousands
of MWhs		1,612		1,833		-12.1	%		2,347		3,029		-22.5	%
Average cost per MWh of
purchased power	$	102.54	$	89.52		14.5	%	$	108.01	$	85.12		26.9	%

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

Purchased power costs decreased for the six months period ended June 30, 2009 compared to the same period in 2008 primarily due to a decrease in volume. MWhs decreased as a result of an increase in self generation and a decrease in total system demand. The average cost per MWh increased significantly primarily due to an increase in the settlement costs for hedging instruments, partially offset by a decrease in natural gas prices.

Deferral of Energy Costs - Net

	Three Months Ended June 30,								Six Months Ended June 30,
	2009		2008			Change from Prior Year %			2009		2008		Change from Prior Year %

Deferred energy costs - net	$	59,809	$	(9,691	)		-717.2	%	$	97,999	$	36,084		171.6	%

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

Amounts for the three months ended June 30, 2009 and 2008 include amortization of deferred energy costs of $10.6 million and $48.4 million, respectively; and an over-collection of amounts recoverable in rates of $49.2 million in 2009 and an under-collection of $58.1 million in 2008. Amounts for the six months ended June 30, 2009 and 2008 include amortization of deferred energy costs of $18.9 million and $88.2 million, respectively; and an over-collection of amounts recoverable in rates of $79.1 million in 2009 and an under-collection of $52.1 million in 2008. Amortization for both the three and six month periods include amounts for the Western Energy Crisis Rate Case and the Reinstatement of deferred energy as discussed in Note 3, Regulatory Actions, of Notes to Financial Statements in NPC’s 2008 Form 10-K.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change from Prior Year %			2009		2008		Change from Prior Year %

Allowance for other funds
used during construction	$	7,552	$	7,692		-1.8	%	$	13,173	$	14,550		-9.5	%

Allowance for borrowed funds used during construction	$	6,106	$	6,020		1.4	%	$	10,668	$	11,375		-6.2	%
	$	13,658	$	13,712		-0.4	%	$	23,841	$	25,925		-8.0	%

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

Other (Income) and Expenses

	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Change from Prior Year %			2009			2008			Change from Prior Year %

Other operating expense	$	68,057		$	62,617			8.7	%	$	138,250		$	119,712			15.5	%
Maintenance expense	$	18,732		$	13,608			37.7	%	$	46,266		$	30,258			52.9	%
Depreciation and amortization	$	53,510		$	42,323			26.4	%	$	105,873		$	82,953			27.6	%
Interest charges on long-term debt	$	57,512		$	41,624			38.2	%	$	109,820		$	82,621			32.9	%
Interest charges-other	$	5,731		$	5,384			6.5	%	$	13,028		$	11,215			16.2	%
Interest accrued on deferred energy	$	(790	)	$	(1,084	)		-27.1	%	$	(2,643	)	$	(2,878	)		-8.2	%
Other income	$	(12,608	)	$	(3,107	)		305.8	%	$	(14,950	)	$	(8,854	)		68.9	%
Other expense	$	7,591		$	1,656			358.4	%	$	10,798		$	3,017			257.9	%

Other operating expense increased for the three and six months ended June 30, 2009, compared to the same period in 2008, primarily due to increased pension expense, costs associated with renewable energy programs, higher uncollectible accounts, operating leases and, operating expenses for the Higgins Generating Station acquired in October 2008 partially offset by lower outside legal services costs.

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

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

Interest charges on Long-Term Debt for the three months and six months ended June 30, 2009, compared to the same period in 2008, increased primarily due to the issuance of $1.1 billion additional long-term debt used to fund significant capital expenditures. This increase was partially offset by lower interest on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2008 Form 10-K and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q for additional information regarding long-term debt.

Interest charges-other for the three months ended June 30, 2009, compared to the same period in 2008, increased due to higher amortization costs related to new debt issues and redemptions. Interest charges-other for the six months ended June 30, 2009, compared to the same period in 2008, increased due to interest on taxes and higher amortization costs related to new debt issues and redemptions.

Interest income accrued on deferred energy balances decreased for the three months and six months ended June 30, 2009, as compared to the same period in 2008, due to lower carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007, offset by overall higher deferred energy balances. See Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

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

Other expense for the three months and six months ended June 30, 2009, compared to the same periods in 2008, increased primarily due to adjustments resulting from the decision in NPC’s most recent GRC. Other expense for the six months ended June 30, 2009 also increased due to the write-off of permitting costs partially offset by lower advertising expenses in 2009.

ANALYSIS OF CASH FLOWS

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

Cash From Operating Activities. The decrease in cash from operating activities was due to several factors, including but not limited to:

•	lower revenues as a result of milder weather and a change in customer usage patterns, as further discussed above under Results of Operations;
•	an increase in costs for operations and maintenance costs for generating facilities, some of which will be included in rates as of July 1, 2009 as a result of NPC’s 2008 GRC as further discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial Statements;
•	funding of approximately $20 million for pension plans;
•	higher interest costs;
•	higher balances for fuel and purchased power costs at year end December 31, 2008, that were subsequently paid in 2009; and
•	prepaid transmission revenues received in 2008.

These decreases were offset partially by over collection of revenues in excess of fuel and purchased power costs, settlement of outstanding litigation, and reduced spending for regulatory activities.

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

Cash From Financing Activities. Cash from financing activities increased due to the issuance of $625 million in new debt. This increase was partially offset by payments on the revolving credit facility, an increase in dividends paid to the parent company, NVE, and 2008 NVE contributions to NPC of $133 million.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

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

As of June 30, 2009, NPC had cash on hand of approximately $35.9 million. NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NPC may use its revolving credit facilities, which have an aggregate of $546 million in available credit as of June 30, 2009, in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. NPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the NPC’s revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, re-finance debt or obtain funding through an equity issuance by NVE.

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

NPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facilities. As of July 31, 2009, NPC had approximately $130.8 million outstanding on its revolving credit facilities including letters of credit. NPC’s long-term credit facility expires in November 2010, and NPC’s Supplemental Revolving Credit Facility expires in January 2010.

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

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

Financing Transactions

Revolving Credit Facilities

General and Refunding Mortgage Notes, Series V

General and Refunding Mortgage Notes, Series U

Factors Affecting Liquidity

Ability to Issue Debt

NPC's $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its Supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2009, NPC was in compliance with these covenants. Based upon estimated interest expense, in order to maintain compliance with these covenants, NPC would be able to utilize all of the available balance under its revolving credit facilities of $546 million. Alternatively, this test would allow NPC to incur $541 million of additional long-term debt.

Furthermore, as discussed in NVE’s Ability to Issue Debt, NPC is subject to NVE’s cap on additional consolidated indebtedness. Although NVE’s cap would, as of June 30, 2009, permit the Utilities to utilize all the remaining balance of $691 million available under the revolving credit facilities, the NVE cap would, alternatively, limit NVE, NPC and SPPC to issuing not more than an aggregate of $197 million of additional long-term debt. As a result, with respect to use of its revolving credit facilities, NPC may utilize all of the available balance of $546 million; however, NPC’s ability to issue additional long-term debt is effectively restricted by NVE’s covenant restrictions, which limit the issuance of long-term debt to $197 million on a consolidated basis. Moreover, NPC’s ability to issue additional long-term debt may be further reduced to the extent that NVE and or SPPC issue additional long-term debt. At this time, it is likely that NPC would rely on its revolving credit facilities for its liquidity needs.

Ability to Issue General and Refunding Mortgage Securities

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

NPC's Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of June 30, 2009, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $610 million of General and Refunding Mortgage Securities as of June 30, 2009. That amount is determined on the basis of:

1.		70% of net utility property additions;
2.		the principal amount of retired General and Refunding Mortgage Securities; and/or
3.		the principal amount of first mortgage bonds retired after October 2001.

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

Credit Ratings

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

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

* Investment grade

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

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of their respective financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

Energy Supplier Matters

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

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of June 30, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $78.9 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements for further discussion.

Gas Supplier Matters

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

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

Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that NPC maintain its Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that NPC’s Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require NPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to NPC, subject to certain caps. As of June 30, 2009, the maximum amount of collateral NPC would be required to post under these agreements is approximately $168.3 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $102.1 million would be required if NPC is downgraded one level, and an additional amount of approximately $66.2 million would be required if NPC is downgraded two levels.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $14.8 million for the three months ended June 30, 2009 compared to net income of $10.8 million for the same period in 2008. During the six months ended June 30, 2009, SPPC recognized net income of approximately $33.9 million compared to $35.1 million for the same period in 2008.

During the six months ended June 30, 2009, SPPC paid $123.8 million in dividends to NVE. On July 31, 2009, SPPC paid $5.0 million in dividends to NVE.

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

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

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

	Three Months Ended June 30,								Six Months Ended June 30,
						Change from									Change from
	2009		2008			Prior Year %			2009			2008			Prior Year %
Operating Revenues:
Electric	$	230,914	$	236,415			-2.3	%	$	468,652		$	486,693			-3.7	%
Gas		31,948		32,152			-0.6	%		112,941			117,746			-4.1	%
	$	262,862	$	268,567			-2.1	%	$	581,593		$	604,439			-3.8	%

Energy Costs:
Fuel for power generation		63,952		60,705			5.3	%		139,994			118,292			18.4	%
Purchased power		29,678		97,363			-69.5	%		66,859			187,469			-64.3	%
Deferral of energy costs-electric-net		29,780		(11,695	)		-354.6	%		41,576			(3,188	)		-1404.1	%
Gas purchased for resale		19,916		27,632			-27.9	%		90,188			94,528			-4.6	%
Deferral of energy costs-gas-net		3,988		(3,774	)		-205.7	%		(363	)		(1,571	)		-76.9	%
	$	147,314	$	170,231			-13.5	%	$	338,254		$	395,530			-14.5	%

Energy Costs by Segment:
Electric	$	123,410	$	146,373			-15.7	%	$	248,429		$	302,573			-17.9	%
Gas		23,904		23,858			0.2	%		89,825			92,957			-3.4	%
	$	147,314	$	170,231			-13.5	%	$	338,254		$	395,530			-14.5	%

Gross Margin by Segment:
Electric	$	107,504	$	90,042			19.4	%	$	220,223		$	184,120			19.6	%
Gas		8,044		8,294			-3.0	%		23,116			24,789			-6.8	%
	$	115,548	$	98,336			17.5	%	$	243,339		$	208,909			16.5	%

Electric gross margin increased for the three and six months ended June 30, 2009 compared to the same period in 2008 primarily due to the increase in BTGR revenue as a result of SPPC’s 2007 GRC, effective July 1, 2008, increased revenues associated with renewable energy programs, and a slight increase in average customer growth. Partially offsetting the increase were decreased short-term transmission revenue and the switching of certain mining customers to DOS.

Gas gross margin decreased for the three and six months ended June 30, 2009 compared to the same period in 2008 primarily due to decreased customer usage as a result of milder weather.

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

Electric Operating Revenue

	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from Prior Year %							Change from Prior Year %
	2009		2008		Change from Prior Year %			2009		2008		Change from Prior Year %
Electric operating revenues:
Residential	$	75,908	$	70,289		8.0	%	$	169,693	$	160,168		6.0	%
Commercial		98,066		93,060		5.4	%		188,504		180,731		4.3	%
Industrial		49,277		62,996		-21.8	%		95,344		128,779		-26.0	%
Retail revenues		223,251		226,345		-1.4	%		453,541		469,678		-3.4	%
Other1		7,663		10,070		-23.9	%		15,111		17,015		-11.2	%
Total revenues	$	230,914	$	236,415		-2.3	%	$	468,652	$	486,693		-3.7	%

Retail sales in thousands
of MWhs		1,942		2,047		-5.1	%		3,922		4,197		-6.6	%

Average retail revenue per MWh	$	114.96	$	110.57		4.0	%	$	115.64	$	111.91		3.3	%

SPPC’s retail revenues decreased for the three and six months ended June 30, 2009 as compared to the same period in 2008 primarily due to lower industrial revenues and a decrease in customer usage due to milder weather during the spring and, in the case of the six month period, warmer winter weather. Industrial revenues decreased primarily due to the transition of Cortez Mine to DOS effective November 1, 2008, and a retail service agreement with Newmont Mining Corporation (“Newmont”) beginning June 1, 2008. These decreases were partially offset by increased retail rates. Retail Rates increased as a result of SPPC’s GRC effective July 1, 2008. For the three months ended June 30, 2009, the average number of residential customers decreased 0.1% while the average number of commercial and industrial customers increased 1.3% and 1.9%, respectively. For the six months ended June 30, 2009, the average number of residential customers decreased 0.1% and the average number of commercial and industrial customers increased 1.5% and 2.6%, respectively.

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

Electric Operating Revenues – Other decreased for the three and six month period ended June 30, 2009 compared to the same period in 2008 primarily due to decreased transmission revenues.

Gas Operating Revenues

	Three Months							Six Months
	Ended June 30,							Ended June 30,
	2009		2008		Change from Prior Year %			2009		2008		Change from Prior Year %
Gas operating revenues:
Residential	$	17,788	$	18,057		-1.5	%	$	63,670	$	68,805		-7.5	%
Commercial		8,439		8,475		-0.4	%		30,279		32,884		-7.9	%
Industrial		3,733		3,866		-3.4	%		9,625		11,853		-18.8	%
Retail revenues		29,960		30,398		-1.4	%		103,574		113,542		-8.8	%
Wholesale revenue		1,425		1,126		26.6	%		8,160		2,804		191.0	%
Miscellaneous		562		628		-10.5	%		1,207		1,400		-13.8	%
Total revenues	$	31,947	$	32,152		-0.6	%	$	112,941	$	117,746		-4.1	%

Retail sales in thousands
of Dths		2,260		2,407		-6.1	%		8,366		9,189		-9.0	%

Average retail revenue per Dth	$	13.26	$	12.63		5.0	%	$	12.38	$	12.36		0.2	%

SPPC’s retail gas revenues decreased for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to decreased customer usage resulting from warmer weather. This decrease was partially offset by increased retail rates as a result of SPPC’s 2009 Natural Gas and Propane BTER update effective April 1, 2009.

SPPC’S retail gas revenues decreased for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to decreased customer usage due to milder weather and lower rates prior to April 1, 2009. The average number of retail customers for the three and six months ended June 30, 2009 increased by 0.3% and 0.4%, respectively.

Wholesale revenues for the three and six months ended June 30, 2009, increased compared to the same periods in 2008 primarily due to increased availability of gas for wholesale sales.

Energy Costs

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

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

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Energy Costs	$	93,630	$	158,068		-40.8	%	$	206,853	$	305,761		-32.3	%
Total System Demand		2,090		2,247		-7.0	%		4,238		4,532		-6.5	%
Average cost per MWh	$	44.80	$	70.35		-36.3	%	$	48.81	$	67.47		-27.7	%

Energy costs and the average cost per MWh for the three and six months ended June 30, 2009 decreased compared to the same period in 2008 due to a significant decrease in natural gas prices and lower purchased power costs primarily as a result of the Newmont Mining Corporation power purchase agreement discussed above in Electric Operating Revenues. Total system demand decreased due to milder weather in 2009, certain customers switching to DOS and a change in customer usage patterns. For the three months ended June 30, 2009, self generation represented 60% of total system compared to 38% for the same period in 2008. For the six months ended June 30, 2009, self generation represented 60% of total system compared to 41% for the same period in 2008.

Fuel For Power Generation

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Fuel for power generation	$	63,952	$	60,706		5.3	%	$	139,994	$	118,292		18.3	%

Thousands of MWh generated		1,245		856		45.4	%		2,523		1,848		36.5	%
Average fuel cost per MWh
of generated power	$	51.37	$	70.92		-27.6	%	$	55.49	$	64.01		-13.3	%

Fuel for power generation costs and volume increased for both three months and six months ended June 30, 2009 as compared to the same period in 2008 primarily due to increased use of the Tracy Generating Station. The average cost per MWh of generated power decreased for both three months and six months ended June 30, 2009, as compared to the same period in 2008 primarily due to lower natural gas prices which were partially offset by higher costs associated with the settlement of hedging instruments.

Purchased Power

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %

Purchased power	$	29,678	$	97,363		-69.5	%	$	66,859	$	187,469		-64.3	%

Purchased power in thousands
of MWhs		845		1,391		-39.3	%		1,715		2,684		-36.1	%
Average cost per MW of
purchased power	$	35.12	$	69.99		-49.8	%	$	38.98	$	69.85		-44.2	%

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

Gas Purchased for Resale

	Three Months Ended June 30,							Six Months Ended June 30,
					Change from							Change from
	2009		2008		Prior Year %			2009		2008		Prior Year %


Gas purchased for resale	$	19,916	$	27,632		-27.9	%	$	90,188	$	94,528		-4.6	%

Gas purchased for resale
(in thousands of decatherms)		2,690		2,565		4.9	%		10,471		9,711		7.8	%

Average cost per decatherm	$	7.40	$	10.77		-31.3	%	$	8.61	$	9.73		-11.5	%

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

Deferral of Energy Costs

	Three Months Ended June 30,								Six Months Ended June 30,
	2009		2008			Change from Prior Year %			2009			2008			Change from Prior Year %

Deferred energy costs - electric - net	$	29,780	$	(11,695	)		-354.6	%	$	41,576		$	(3,188	)		-1404.1	%
Deferred energy costs - gas - net		3,987		(3,774	)		-205.6	%		(363	)		(1,571	)		-76.9	%
	$	33,767	$	(15,469	)				$	41,213		$	(4,759	)

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

Deferral of energy costs - electric – net for the three months ended June 30, 2009 and 2008 reflect amortization of deferred energy costs of ($0.4) million and $8.6 million respectively; and an over-collection of amounts recoverable in rates of $30.2 million in 2009, and an under-collection of $20.3 million in 2008. For the six months ended June 30, 2009 and 2008, amortization of deferred energy costs were ($1.2) million and $18.6 million, respectively; with an over-collection of amounts recoverable in rates of $42.8 million in 2009, and under-collection of $21.8 million in 2008.

Deferred energy costs - gas - net for the three months ended June 30, 2009 and 2008 reflect amortization of deferred energy costs of $0.0 million, and ($0.2) million, respectively; and an over-collection of amounts recoverable in rates in 2009 of $4.0 million and an under-collection of $3.5 million in 2008. For the six months ended June 30, 2009 and 2008, amortization of deferred energy costs were $0.0 million and ($0.9) million, respectively; with an under-collection of amounts recoverable in rates of $0.4 million and $0.7 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change from Prior Year %			2009		2008		Change from Prior Year %

Allowance for other funds
used during construction	$	996	$	5,421		-81.6	%	$	1,593	$	10,520		-84.9	%

Allowance for borrowed funds used during construction	$	916	$	4,068		-77.5	%	$	1,500	$	7,865		-80.9	%
	$	1,912	$	9,489		-79.9	%	$	3,093	$	18,385		-83.2	%

AFUDC decreased for the three and six months ended June 30, 2009 compared to the same period in 2008, primarily due to the completion of the Tracy Generating Station in July of 2008, which resulted in a decrease in the CWIP balance.

Other (Income) and Expense

	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Change from Prior Year %			2009			2008			Change from Prior Year %

Other operating expense	$	40,890		$	34,765			17.6	%	$	84,905		$	68,270			24.4	%
Maintenance expense	$	8,900		$	7,864			13.2	%	$	15,766		$	14,336			10.0	%
Depreciation and amortization	$	26,813		$	22,018			21.8	%	$	52,498		$	43,458			20.8	%
Interest charges on long-term debt	$	16,245		$	18,578			-12.6	%	$	33,060		$	37,340			-11.5	%
Interest charges-other	$	1,430		$	1,369			4.5	%	$	3,126		$	2,991			4.5	%
Interest accrued on deferred energy	$	1,044		$	627			66.5	%	$	1,717		$	1,185			44.9	%
Other income	$	(5,792	)	$	(1,229	)		371.3	%	$	(8,507	)	$	(8,964	)		-5.1	%
Other expense	$	1,797		$	2, 881			-37.6	%	$	3,788		$	4,681			-19.1	%

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

Maintenance expense increased for the three and six months ended June 30, 2009, compared to the same period in 2008, mainly due to the addition of the Tracy Generating Station expansion that became operational in summer of 2008, partially offset by outages at Valmy Generating Station for boiler repairs in 2008.

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

Interest charges on long-term debt decreased for the three months and six months ended June 30, 2009 compared to the same periods in 2008 primarily due to the repurchase of certain variable rate debt, lower interest rates on variable rate debt, and the redemption of $99 million Series A General and Refunding Mortgage Bonds in June 2008. These amounts were partially offset by the issuance of $250 million Series Q General and Refunding Mortgage Notes in September 2008 and higher long term credit facility balances in 2009. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2008 10-K and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q for additional information regarding long-term debt .

Interest charges-other for the three months and six months ended June 30, 2009 did not change materially from the same period in 2008.

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

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

Other expense decreased during the three months and six months ended June 30, 2009, when compared to the same period in 2008, due to lower advertising costs in 2009 and adjustments made in 2008 as a result of SPPC’s GRC. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2008 Form 10-K for further information.

ANALYSIS OF CASH FLOWS

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

Cash From Operating Activities. The increase in cash from operating activities was primarily due to the following:

•	an increase in revenues as a result of SPPC’s 2007 GRC;
•	the over collection of revenues in excess of fuel of and purchased power costs;
•	reduced spending for regulatory activities; and
•	reduced interest paid

These increases to cash from operating activities were partially offset by the funding of retirement plans and higher balances for fuel and purchased power costs at year end December 31, 2008, that were subsequently paid in 2009.

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

Cash From Financing Activities. The decrease in cash from financing activities is primarily due to higher dividends paid to NVE and reduced borrowings against the revolving credit facility in 2009. These decreases were partially offset by an increase in investment by NVE in 2009.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

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

As of June 30, 2009, SPPC had cash on hand of approximately $19.1 million. SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, SPPC may use its revolving credit facility which has $145 million of available credit as of June 30, 2009, in order to meet its liquidity needs. SPPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the SPPC’s revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

SPPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facility. As of July 31, 2009, SPPC had $189.3 million outstanding on its revolving credit facility, including letters of credit. SPPC’s long-term credit facility expires in November 2010.

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

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

Financing Transactions

Revolving Credit Facility

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

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

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

Factors Affecting Liquidity

Ability to Issue Debt

As of June 30, 2009, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

Furthermore, as discussed in NVE’s Ability to Issue Debt, SPPC is subject to NVE’s cap on additional consolidated indebtedness. Although NVE’s cap would, as of June 30, 2009, permit the Utilities to utilize all of the remaining balance of $691 million available under their revolving credit facilities, the NVE cap would, alternatively, limit NVE, NPC and SPPC to issuing not more than an aggregate $197 million of additional long-term debt. As a result, with respect to use of its revolving credit facility SPPC may utilize all of the available balance of $145 million; however, SPPC’s ability to issue additional long-term debt is effectively restricted by NVE’s covenant restrictions which limits the issuance of long-term debt to $197 million on a consolidated basis. Moreover, SPPC’s ability to issue additional long-term debt may be further reduced to the extent that NVE and/or NPC issue additional long-term debt. At this time, it is likely that SPPC would rely on its revolving credit facilities for its liquidity needs.

Ability to Issue General and Refunding Mortgage Securities

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

1.	70% of net utility property additions;
2.	the principal amount of retired General and Refunding Mortgage Securities; and/or
3.	the principal amount of first mortgage bonds retired after October 2001.

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

Credit Ratings

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

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

* Investment grade

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

Cross Default Provisions

None of the financing agreements of SPPC contains a cross-default provision that would result in an event of default by SPPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

Energy Supplier Matters

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

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. Under the net mark-to-market value as of June 30, 2009 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements for further discussion.

Gas Supplier Matters

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

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that SPPC maintain its Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that SPPC’s Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require SPPC to post cash or a letter of credit to the extent the counterparties have mark to market exposure to SPPC, subject to certain caps. As of June 30, 2009, the maximum amount of collateral SPPC would be required to post under these agreements is approximately $74.3 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $38.9 million would be required if SPPC is downgraded one level and an additional amount of approximately $35.4 million would be required if SPPC is downgraded two levels.

REGULATORY PROCEEDINGS (UTILITIES)

NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and the CPUC. In addition, the PUCN, the CPUC or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between NVE, NPC and/or SPPC and/or any other affiliated company.

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit IRPs to the PUCN for approval.

Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover or refund any under or over collection of prior energy costs and the BTER Updates recover current energy costs. As of June 30, 2009, NPC’s and SPPC’s balance sheets included approximately $185 million and credits of $72 million, respectively, of deferred energy costs of which $107 million and credits of $45 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

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

RECENT PRONOUNCEMENTS

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

ITEM 3A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2009, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

	June 30, 2009
	Expected Maturity Date
																					Fair
	2009		2010			2011			2012			2013			Thereafter			Total			Value
Long-term Debt
NVE
Fixed Rate	$	-	$	-		$	-		$	63,670		$	-		$	421,539		$	485,209		$	458,774
Average Interest Rate		-		-			-			7.80	%		-			7.77	%		7.78	%

NPC
Fixed Rate	$	-	$	-		$	364,000		$	130,000		$	-		$	2,894,335		$	3,388,335		$	3,391,130
Average Interest Rate		-		-			8.14	%		6.50	%		-			6.53	%		6.70	%
Variable Rate	$	-	$	115,000		$	-		$	-		$	-		$	179,500		$	294,500		$	294,500
Average Interest Rate		-		1.07	%		-			-			-			1.23	%		1.17	%

SPPC
Fixed Rate	$	-	$	-		$	-		$	100,000		$	250,000		$	625,000		$	975,000		$	999,705
Average Interest Rate		-		-			-			6.25	%		5.45	%		6.39	%		6.13	%
Variable Rate	$	-	$	171,000		$	-		$	-		$	-		$	218,500		$	389,500		$	389,500
Average Interest Rate		-		1.08	%		-			-			-			1.29	%		1.19	%

Total Debt	$	-	$	286,000		$	364,000		$	293,670		$	250,000		$	4,338,874		$	5,532,544		$	5,533,609

Commodity Price Risk

See the 2008 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2008.

Credit Risk

The Utilities monitor and manage credit risk with their counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with counterparties was approximately $87.8 million as of June 30, 2009, which compares to balances of $334.3 million at December 31, 2008, and $865.4 million at June 30, 2008. The decrease from December 31, 2008 is primarily due to the decrease in prices of natural gas during the first six months of 2009.

ITEM 4 AND ITEM 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of June 30, 2009, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the second quarter of 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

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

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

FERC 206 complaints

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

In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC. The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy Supply Company, American Electric Power Service Corporation and BP Energy, and stayed the case pending settlement discussions. The Utilities, together with other interested parties, have settled and resolved all claims against BP Energy and submitted a settlement agreement with FERC for public comment and FERC consideration. No comments were filed and FERC consideration of the settlement is pending. The Utilities previously had negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron. The Utilities continue discussions with Allegheny Energy Supply Company and American Electric Power Service Corporation. Management cannot predict the timing or outcome of a decision in the remaining matters.

Other Legal Matters

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

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2008 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2008 Form 10-K, and quarterly reports on Form 10-Q for the quarter ended March 31, 2009.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

The 2009 Annual Meeting of the Stockholders of NV Energy, Inc. was held at 10:00 a.m., Pacific Daylight Time, on Thursday, April 30, 2009, at the General Office Building of NV Energy, 6100 Neil Road, Reno, Nevada.

Three proposals were presented for stockholder consideration: (1) election of five members of the BOD to serve until the Annual Meeting in 2012, and until their successors are elected and qualified; (2) to amend NVE’s Articles of Incorporation to provide for the phase-in of annual elections of Directors; (3) to ratify the selection of NVE’s independent registered public accounting firm. Set forth below are the final voting results with respect to each proposal.

Five Directors, Susan F. Clark, Theodore J. Day, Stephen E. Frank, Maureen T. Mullarkey and Donald D. Snyder, were elected to serve three year terms expiring at the 2012 Annual Meeting of Stockholders. A plurality of the votes cast was required for the election of each Director. Directors whose term expires in 2010: Brian J. Kennedy, John F. O’Reilly, and Michael W. Yackira. Directors whose term expires in 2011: Joseph B. Anderson, Jr., Glenn C. Christenson and Philip G. Satre.

The certified voting results are shown below:

Election of Directors	For	Withheld

Susan F. Clark	210,389,379	1,679,045
Theodore J. Day	98,478,848	113,589,576
Stephen E. Frank	188,856,294	23,212,130
Maureen T. Mullarkey	210,499,532	1,568,892
Donald D. Snyder	185,066,532	27,001,892

The proposal requesting to amend NVE’s Articles of Incorporation to provide for the phase-in of annual elections of Directors received the votes as set forth below. A majority of the votes entitled to be cast at the Annual Meeting was required to approve the Shareholder proposal; accordingly, the proposal was approved.

For	Against	Abstain

209,742,740	2,133,012	212,672
89.51%	0.91%	0.0907%

The proposal requesting to ratify the selection of NVE’s independent registered public accounting firm received the votes as set forth below. A majority of the votes cast at the Annual Meeting was required to approve this proposal; accordingly, the proposal was approved.

For	Against	Abstain

208,919,809	2,837,298	311,317
89.16%	1.21%	0.133%

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.

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: August 3, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 3, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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

Date: August 3, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 3, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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

Date: August 3, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: August 3, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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Sierra Pacific Power 10-Q2009 Q2 Quarterly report

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