Nevada Power (NVP) 10-Q 2011 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

OR

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

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation
1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada  89146
	(702) 402-5000
2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000
0-00508	SIERRA PACIFIC POWER COMPANY d/b/a	88-0044418	Nevada
	NV ENERGY
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

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

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

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

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

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

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

Class	Outstanding at August 4, 2011
Common Stock, $1.00 par value of NV Energy, Inc.	235,990,761 Shares

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

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

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

1

NV ENERGY, INC. NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY QUARTERLY REPORTS ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2011 TABLE OF CONTENTS
	PART I – FINANCIAL INFORMATION
	Acronyms & Terms			3
	ITEM 1.	Financial Statements
		NV Energy, Inc.
			Consolidated Income Statements  – Three and Six Months Ended June 30, 2011 and 2010	5
			Consolidated Balance Sheet – June 30, 2011 and December 31, 2010	6
			Consolidated Statements of Cash Flows - Three and Six Months Ended June 30, 2011 and 2010	8
			Consolidated Statements of Shareholders’ Equity - Three and Six Months Ended June 30, 2011 and 2010	9
		Nevada Power Company
			Consolidated Income Statements  – Three and Six Months Ended June 30, 2011 and 2010	10
			Consolidated Balance Sheet – June 30, 2011 and December 31, 2010	11
			Consolidated Statements of Cash Flows - Three and Six Months Ended June 30, 2011 and 2010	13
			Consolidated Statements of Shareholder’s Equity - Three and Six Months Ended June 30, 2011 and 2010	14
		Sierra Pacific Power Company
			Consolidated Income Statements – Three and Six Months Ended June 30, 2011 and 2010	15
			Consolidated Balance Sheet – June 30, 2011 and December 31, 2010	16
			Consolidated Statements of Cash Flows - Three and Six Months Ended June 30, 2011 and 2010	18
			Consolidated Statements of Shareholder’s Equity - Three and Six Months Ended June 30, 2011 and 2010	19
		Condensed Notes to Financial Statements
			Note 1.     Summary of Significant Accounting Policies	20
			Note 2.     Segment Information	21
			Note 3.     Regulatory Actions	23
			Note 4.     Long-Term Debt	27
			Note 5.     Fair Value of Financial Instruments	27
			Note 6.     Derivatives and Hedging Activities	28
			Note 7.     Retirement Plan and Post-Retirement Benefits	29
			Note 8.     Commitments and Contingencies	31
			Note 9.     Earnings per Share (NVE)	34
			Note 10.  Assets Held for Sale	34
			Note 11.  Dividends	34
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
		NV Energy, Inc.		41
		Nevada Power Company		45
		Sierra Pacific Power Company		53
	ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		63
	ITEM 4.	Controls and Procedures		63
	PART II – OTHER INFORMATION
	ITEM 1.	Legal Proceedings		64
	ITEM 1A.	Risk Factors		64
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		64
	ITEM 3.	Defaults Upon Senior Securities		64
	ITEM 5.	Other Information		64
	ITEM 6.	Exhibits		65
	Signature Page and Certifications			67

2

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)
Acronym/Term	Meaning
2010 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2010
AFUDC-debt	Allowance for Borrowed Funds Used During Construction
AFUDC-equity	Allowance for Equity Funds Used During Construction
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CalPeco	California Pacific Electric Company
CWIP	Construction Work-in-Progress
d/b/a	Doing business as
DEAA	Deferred Energy Accounting Adjustment
DSM	Demand Side Management
Dth	Decatherm
EEC	Ely Energy Center
EEIR	Energy Efficiency Implementation Rate
EEPR	Energy Efficiency Program Rate
EPA	Environmental Protection Agency
EPS	Earnings Per Share
EWAM	Enterprise Work Asset Management System
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd.
Fort Chuchill	226 megawatt nominally rated Fort Churchill Generating Station
GAAP	Generally Accepted Accounting Principles in the United States
GBT	Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC
GBT-South	Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT
GRC	General Rate Case
Harry Allen Generating Station	142 megawatt nominally rated Harry Allen Generating Station
Higgins Generating Station	598 megawatt nominally rated Walter M. Higgins, III Generating Station
Independence Lake	2,325 acres of forestland in the Sierra Nevada Mountains purchased from NV Energy, Inc. by The Nature Conservancy
IRP	Integrated Resource Plan
kV	Kilovolt
kWh	Kilowatt hour
Legislature	Nevada State Legislature
Lenzie Generating Station	1,102 megawatt nominally rated Chuck Lenzie Generating Station
MMBtu	Million British Thermal Units
Mohave Generating Station	1,580 megawatt nominally rated Mohave Generating Station
Moody’s	Moody’s Investors Services, Inc.
MW	Megawatt
MWh	Megawatt hour
Navajo Generating Station	255 megawatt nominally rated Navajo Generating Station
NEICO	Nevada Electrical Investment Company
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NPC	Nevada Power Company d/b/a NV Energy
NPC Credit Agreement	$600 million Revolving Credit Facility entered into in April 2010 between NPC and Wells Fargo, N.A., as administrative agent for the lenders a party thereto
NPC’s Indenture	NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank of New York Mellon Trust Company, N.A., as Trustee
NRSRO	Nationally Recognized Statistical Rating Organization
NVE	NV Energy, Inc.
NV Energize	A smart grid infrastructure that is expected to enable the widespread use of smart meters that will provide customers the ability to more directly manage their energy usage.
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC	Portfolio Energy Credit
Portfolio Standard	Nevada Renewable Energy Portfolio Standard
PPA	Purchased Power Agreement
PUCN	Public Utilities Commission of Nevada
Reid Gardner Generating Station	325 megawatt nominally rated Reid Gardner Generating Station
REPR	Renewable Energy Program Rate
ROE	Return on Equity
ROR	Rate of Return
S&P	Standard & Poor’s
Salt River	Salt River Project
SEC	United States Securities and Exchange Commission
Silverhawk Generating Station	395 megawatt nominally rated Silverhawk Generating Station
SNWA	Southern Nevada Water Authority
SPPC	Sierra Pacific Power Company d/b/a NV Energy

3

SPPC Credit Agreement	$250 million Revolving Credit Facility entered into in April 2010 between SPPC and Bank of America, N.A., as administrative agent for the lenders a party thereto
SPPC’s Indenture	SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and the Bank of New York Mellon Trust Company, N.A., as Trustee
TMWA	Truckee Meadows Water Authority
Tracy Generating Station	541 megawatt nominally rated Frank A. Tracy Generating Station
TRED	Temporary Renewable Energy Development
TUA	Transmission Use and Capacity Exchange Agreement with GBT-South
U.S.	United States of America
Utilities	Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station	261 megawatt nominally rated Valmy Generating Station
VIE	Variable Interest Entity
WSPP	Western Systems Power Pool

4

NV ENERGY, INC.
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	674,931		$	782,683		$	1,315,914		$	1,497,172
OPERATING EXPENSES:
Fuel for power generation		156,803			181,662			303,141			403,281
Purchased power		160,308			165,321			295,324			272,684
Gas purchased for resale		24,984			25,154			77,616			90,713
Deferred energy		(8,106	)		54,933			(10,058	)		72,499
Other operating expenses		97,547			101,388			203,521			208,014
Maintenance		32,186			28,860			61,948			54,589
Depreciation and amortization		89,606			84,696			172,708			165,644
Taxes other than income		14,684			15,939			30,929			32,112
Total Operating Expenses		568,012			657,953			1,135,129			1,299,536
OPERATING INCOME		106,919			124,730			180,785			197,636
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $2,835, $5,926, $9,045 and $10,864)		(80,879	)		(80,772	)		(158,222	)		(160,836	)
Interest income (expense) on regulatory items		(4,062	)		(2,997	)		(7,824	)		(5,068	)
AFUDC-equity		3,522			7,138			11,164			13,091
Other income		4,439			15,401			10,297			21,278
Other expense		(9,087	)		(9,659	)		(13,743	)		(12,725	)
Total Other Income (Expense)		(86,067	)		(70,889	)		(158,328	)		(144,260	)
Income Before Income Tax Expense		20,852			53,841			22,457			53,376
Income tax expense		7,964			16,895			7,239			18,151
NET INCOME	$	12,888		$	36,946		$	15,218		$	35,225
Amount per share basic and diluted - (Note 9)
Net income per share basic and diluted	$	0.05		$	0.16		$	0.06		$	0.15
Weighted Average Shares of Common Stock Outstanding - basic		235,867,068			234,995,083			235,697,687			234,927,239
Weighted Average Shares of Common Stock Outstanding - diluted		237,278,546			236,134,449			237,027,656			235,965,452
Dividends Declared Per Share of Common Stock	$	0.12		$	0.11		$	0.24		$	0.22
The accompanying notes are an integral part of the financial statements.

5

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
		June 30,		December 31,
		2011		2010
ASSETS
Current Assets:
Cash and cash equivalents		$	110,736	$	86,189
Accounts receivable less allowance for uncollectible accounts:
	2011 - $28,594; 2010 - $28,684		399,798		354,010
Materials, supplies and fuel, at average cost			129,259		114,520
Risk management assets (Note 6)			394		4,007
Current income taxes receivable			82		82
Deferred income taxes			122,455		130,800
Other current assets			37,369		42,330
Total Current Assets			800,093		731,938
Utility Property:
Plant in service			11,914,546		11,068,518
Construction work-in-progress			311,119		908,579
Total			12,225,665		11,977,097
Less accumulated provision for depreciation			3,129,377		3,047,438
Total Utility Property, Net			9,096,288		8,929,659
Investments and other property, net			58,514		61,613
Deferred Charges and Other Assets:
Deferred energy (Note 3)			111,135		117,623
Regulatory assets			1,159,933		1,237,159
Regulatory asset for pension plans			258,350		269,472
Other deferred charges and assets			158,466		166,882
Total Deferred Charges and Other Assets			1,687,884		1,791,136
Assets Held for Sale (Note 10)			-		155,322
TOTAL ASSETS		$	11,642,779	$	11,669,668

(Continued)

6

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
	June 30,			December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY	2011			2010
Current Liabilities:
Current maturities of long-term debt (Note 4)	$	135,991		$	355,929
Accounts payable		359,164			346,409
Accrued expenses		124,554			133,851
Risk management liabilities (Note 6)		5,297			33,229
Deferred energy (Note 3)		312,652			315,839
Other current liabilities		66,704			70,638
Total Current Liabilities		1,004,362			1,255,895
Long-Term Debt (Note 4)		5,151,590			4,924,109
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		1,244,182			1,246,410
Deferred investment tax credit		17,369			19,204
Accrued retirement benefits		155,595			148,841
Regulatory liabilities		434,326			428,114
Other deferred credits and liabilities		315,649			265,571
Total Deferred Credits and Other Liabilities		2,167,121			2,108,140
Liabilities Held for Sale (Note 10)		-			30,706
Shareholders' Equity:
Common stock, $1.00 par value; 350 million shares authorized; 235,977,042 and 235,322,553 issued and outstanding for 2011 and 2010		235,977			235,323
Other paid-in capital		2,713,684			2,705,954
Retained earnings		375,063			416,432
Accumulated other comprehensive loss		(5,018	)		(6,891	)
Total Shareholders' Equity		3,319,706			3,350,818
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	11,642,779		$	11,669,668
The accompanying notes are an integral part of the financial statements.

(Concluded)

7

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
	For the Six Months Ended
	June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	15,218		$	35,225
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		172,708			165,644
Deferred taxes and deferred investment tax credit		7,889			18,160
AFUDC-equity		(11,164	)		(13,091	)
Deferred energy		3,447			92,909
Gain on sale of asset		-			(7,575	)
Amortization of other regulatory assets		78,080			42,831
Deferred rate increase		32,239			(4,103	)
Other, net		7,022			11,619
Changes in certain assets and liabilities:
Accounts receivable		(41,535	)		(22,235	)
Materials, supplies and fuel		(14,541	)		4,101
Other current assets		4,961			5,469
Accounts payable		34,980			8,749
Accrued retirement benefits		6,755			(9,306	)
Other current liabilities		(13,230	)		(1,790	)
Risk management assets and liabilities		1,468			5,067
Other deferred assets		(2,884	)		(2,462	)
Other regulatory assets		(61,796	)		(23,329	)
Other deferred liabilities		(17,098	)		(4,999	)
Net Cash from Operating Activities		202,519			300,884
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(310,207	)		(368,882	)
Proceeds from sale of asset		131,789			18,225
Customer advances for construction		(3,789	)		(5,380	)
Contributions in aid of construction		47,213			35,466
Investments and other property - net		407			(225	)
Net Cash used by Investing Activities		(134,587	)		(320,796	)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		387,230			414,279
Retirement of long-term debt		(367,468	)		(274,821	)
Settlement of interest rate lock		(14,944	)		-
Sale of common stock		8,384			3,246
Dividends paid		(56,587	)		(51,693	)
Net Cash from (used by) Financing Activities		(43,385	)		91,011
Net Increase in Cash and Cash Equivalents		24,547			71,099
Beginning Balance in Cash and Cash Equivalents		86,189			62,706
Ending Balance in Cash and Cash Equivalents	$	110,736		$	133,805
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	156,656		$	163,649
Income taxes	$	1		$	14
Significant non-cash transactions:
Accrued construction expenses as of June 30,	$	115,412		$	80,453
Capital lease obligations incurred	$	-		$	15,336
The accompanying notes are an integral part of the financial statements.

8

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands, Except Share Amounts)
	Common Stock Shares		Common Stock Amount		Other Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
December 31, 2009		234,834,169	$	234,834	$	2,700,329	$	295,247		$	(6,488	)	$	3,223,922
Net Income								35,225						35,225
Dividend Reinvestment and Employee Benefits		272,249		272		2,974								3,246
Change in compensation retirement benefits liability and amortization (net of taxes ($34))											63			63
Dividends Declared								(51,693	)					(51,693	)
June 30, 2010		235,106,418	$	235,106	$	2,703,303	$	278,779		$	(6,425	)	$	3,210,763
December 31, 2010		235,322,553		235,323		2,705,954		416,432			(6,891	)		3,350,818
Net Income								15,218						15,218
Dividend Reinvestment and Employee Benefits		654,489		654		7,418								8,072
Tax benefit from stock options exercised						312								312
Change in compensation retirement benefits liability and amortization (net of taxes ($1,009))											1,873			1,873
Dividends Declared								(56,587	)					(56,587	)
June 30, 2011		235,977,042	$	235,977	$	2,713,684	$	375,063		$	(5,018	)	$	3,319,706
The accompanying notes are an integral part of the financial statements.

9

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	473,898		$	539,395		$	863,966		$	965,194
OPERATING EXPENSES:
Fuel for power generation		114,744			132,067			215,814			288,182
Purchased power		122,408			124,740			217,974			195,967
Deferred energy		2,350			39,960			9,080			59,423
Other operating expenses		61,935			63,292			127,036			130,011
Maintenance		19,325			18,219			41,662			35,238
Depreciation and amortization		61,913			57,654			119,586			112,755
Taxes other than income		9,046			9,793			19,104			19,819
Total Operating Expenses		391,721			445,725			750,256			841,395
OPERATING INCOME		82,177			93,670			113,710			123,799
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $2,330, $5,444, $8,120 and $9,976)		(55,736	)		(53,996	)		(107,769	)		(107,352	)
Interest income (expense) on regulatory items		(1,982	)		(777	)		(3,433	)		(808	)
AFUDC-equity		2,855			6,398			9,953			11,760
Other income		2,676			2,659			6,308			5,242
Other expense		(5,179	)		(5,172	)		(7,911	)		(6,304	)
Total Other Income (Expense)		(57,366	)		(50,888	)		(102,852	)		(97,462	)
Income Before Income Tax Expense		24,811			42,782			10,858			26,337
Income tax expense		8,748			12,998			3,815			8,879
NET INCOME	$	16,063		$	29,784		$	7,043		$	17,458
The accompanying notes are an integral part of the financial statements.

10

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
		June 30,		December 31,
		2011		2010
ASSETS
Current Assets:
Cash and cash equivalents		$	26,329	$	60,077
Accounts receivable less allowance for uncollectible accounts:
	2011 - $26,012; 2010 - $26,428		287,697		224,704
Materials, supplies and fuel, at average cost			66,810		66,459
Risk management assets (Note 6)			372		3,476
Deferred income taxes			74,544		76,282
Other current assets			27,085		29,680
Total Current Assets			482,837		460,678
Utility Property:
Plant in service			8,385,715		7,552,097
Construction work-in-progress			199,625		825,079
Total			8,585,340		8,377,176
Less accumulated provision for depreciation			1,880,362		1,828,366
Total Utility Property, Net			6,704,978		6,548,810
Investments and other property, net			51,981		55,305
Deferred Charges and Other Assets:
Deferred energy (Note 3)			111,135		117,623
Regulatory assets			832,911		871,982
Regulatory asset for pension plans			127,114		133,410
Other deferred charges and assets			116,649		114,016
Total Deferred Charges and Other Assets			1,187,809		1,237,031
TOTAL ASSETS		$	8,427,605	$	8,301,824

(Continued)

11

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
	June 30,			December 31,
	2011			2010
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt (Note 4)	$	135,991		$	355,929
Accounts payable		235,092			232,279
Accounts payable, affiliated companies		47,665			29,334
Accrued expenses		85,380			89,638
Risk management liabilities (Note 6)		4,427			22,764
Deferred energy (Note 3)		182,949			171,349
Other current liabilities		51,454			54,607
Total Current Liabilities		742,958			955,900
Long-Term Debt (Note 4)		3,465,040			3,221,833
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		911,324			908,094
Deferred investment tax credit		6,702			7,255
Accrued retirement benefits		34,564			31,907
Regulatory liabilities		229,552			225,983
Other deferred credits and liabilities		238,837			189,220
Total Deferred Credits and Other Liabilities		1,420,979			1,362,459
Shareholder's Equity:
Common stock, $1.00 par value, 1,000 shares authorized, issued and outstanding for 2011 and 2010		1			1
Other paid-in capital		2,308,219			2,254,219
Retained earnings		493,331			511,288
Accumulated other comprehensive loss		(2,923	)		(3,876	)
Total Shareholder's Equity		2,798,628			2,761,632
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	8,427,605		$	8,301,824
The accompanying notes are an integral part of the financial statements.

(Concluded)

12

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
	For the Six Months Ended
	June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	7,043		$	17,458
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		119,586			112,755
Deferred taxes and deferred investment tax credit		4,253			9,137
AFUDC-equity		(9,953	)		(11,760	)
Deferred energy		18,088			72,096
Amortization of other regulatory assets		38,789			29,000
Deferred rate increase		32,239			(4,103	)
Other, net		514			5,289
Changes in certain assets and liabilities:
Accounts receivable		(62,992	)		(59,089	)
Materials, supplies and fuel		(153	)		3,871
Other current assets		2,595			(417	)
Accounts payable		47,878			10,510
Accrued retirement benefits		2,657			(8,963	)
Other current liabilities		(7,412	)		345
Risk management assets and liabilities		960			3,506
Other deferred assets		(2,405	)		(1,364	)
Other regulatory assets		(43,700	)		(13,964	)
Other deferred liabilities		(15,713	)		(1,980	)
Net Cash from Operating Activities		132,274			162,327
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(252,654	)		(295,827	)
Proceeds from sale of asset		-			3,254
Customer advances for construction		(1,660	)		(3,312	)
Contributions in aid of construction		38,229			33,568
Investments and other property - net		391			(196	)
Net Cash used by Investing Activities		(215,694	)		(262,513	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		387,329			391,266
Retirement of long-term debt		(351,713	)		(233,765	)
Settlement of interest rate lock		(14,944	)		-
Additional investment by parent company		54,000			-
Dividends paid		(25,000	)		(53,000	)
Net Cash from Financing Activities		49,672			104,501
Net (Decrease)/Increase in Cash and Cash Equivalents		(33,748	)		4,315
Beginning Balance in Cash and Cash Equivalents		60,077			42,609
Ending Balance in Cash and Cash Equivalents	$	26,329		$	46,924
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	110,916		$	111,657
Income taxes	$	1		$	2
Significant non-cash transactions:
Accrued construction expenses as of June 30,	$	97,905		$	72,770
Capital lease obligations incurred	$	-		$	15,336
The accompanying notes are an integral part of the financial statements.

13

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands, Except Share Amounts)
	Common Stock Shares		Common Stock Amount		Other Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholder's Equity
December 31, 2009		1,000	$	1	$	2,254,189	$	399,345		$	(3,496	)	$	2,650,039
Net Income								17,458						17,458
Change in compensation retirement benefits liability and amortization (net of taxes ($18))											33			33
Dividends Declared								(53,000	)					(53,000	)
June 30, 2010		1,000	$	1	$	2,254,189	$	363,803		$	(3,463	)	$	2,614,530
December 31, 2010		1,000		1		2,254,219		511,288			(3,876	)		2,761,632
Net Income								7,043						7,043
Capital contribution from parent						54,000								54,000
Change in compensation retirement benefits  liability and amortization (net of taxes ($513))											953			953
Dividends Declared								(25,000	)					(25,000	)
June 30, 2011		1,000	$	1	$	2,308,219	$	493,331		$	(2,923	)	$	2,798,628
The accompanying notes are an integral part of the financial statements.

14

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
OPERATING REVENUES:
Electric	$	164,582		$	202,877		$	343,199		$	411,539
Gas		36,448			40,405			108,742			120,425
Total Operating Revenues		201,030			243,282			451,941			531,964
OPERATING EXPENSES:
Fuel for power generation		42,059			49,595			87,327			115,099
Purchased power		37,900			40,581			77,350			76,717
Gas purchased for resale		24,984			25,154			77,616			90,713
Deferral of energy - electric - net		(11,898	)		8,725			(23,829	)		7,225
Deferral of energy - gas - net		1,442			6,248			4,691			5,851
Other operating expenses		34,687			37,014			74,903			76,367
Maintenance		12,861			10,641			20,286			19,351
Depreciation and amortization		27,693			27,042			53,122			52,889
Taxes other than income		5,599			6,098			11,623			12,164
Total Operating Expenses		175,327			211,098			383,089			456,376
OPERATING INCOME		25,703			32,184			68,852			75,588
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: $505, $482, $925 and $888)		(16,774	)		(17,113	)		(33,720	)		(34,158	)
Interest income (expense) on regulatory items		(2,080	)		(2,220	)		(4,391	)		(4,260	)
AFUDC-equity		667			740			1,211			1,331
Other income		1,177			10,142			3,229			11,897
Other expense		(3,554	)		(4,401	)		(5,148	)		(6,270	)
Total Other Income (Expense)		(20,564	)		(12,852	)		(38,819	)		(31,460	)
Income Before Income Tax Expense		5,139			19,332			30,033			44,128
Income Tax Expense		1,627			8,017			9,945			15,693
NET INCOME	$	3,512		$	11,315		$	20,088		$	28,435
The accompanying notes are an integral part of the financial statements.

15

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
		June 30,		December 31,
		2011		2010
ASSETS
Current Assets:
Cash and cash equivalents		$	76,093	$	9,552
Accounts receivable less allowance for uncollectible accounts:
	2011 - $2,582; 2010 - $2,256		112,041		129,306
Materials, supplies and fuel, at average cost			62,449		48,061
Risk management assets (Note 6)			22		531
Intercompany income taxes receivable			10,351		10,351
Deferred income taxes			60,105		53,282
Other current assets			7,330		11,633
Total Current Assets			328,391		262,716
Utility Property:
Plant in service			3,528,831		3,516,421
Construction work-in-progress			111,494		83,500
Total			3,640,325		3,599,921
Less accumulated provision for depreciation			1,249,015		1,219,072
Total Utility Property, Net			2,391,310		2,380,849
Investments and other property, net			6,181		5,956
Deferred Charges and Other Assets:
Regulatory assets			327,023		365,177
Regulatory asset for pension plans			128,247		131,734
Other deferred charges and assets			34,777		45,268
Total Deferred Charges and Other Assets			490,047		542,179
Assets Held for Sale (Note 10)			-		155,322
TOTAL ASSETS		$	3,215,929	$	3,347,022

(Continued)

16

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Shares)
(Unaudited)
	June 30,			December 31,
	2011			2010
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Accounts payable	$	89,492		$	90,206
Accounts payable, affiliated companies		18,295			10,812
Accrued expenses		29,902			33,788
Dividends declared		-			54,000
Risk management liabilities (Note 6)		870			10,465
Deferred energy (Note 3)		129,703			144,490
Other current liabilities		15,248			16,029
Total Current Liabilities		283,510			359,790
Long-term debt (Note 4)		1,180,051			1,195,775
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
Deferred income taxes		410,184			395,454
Deferred investment tax credit		10,667			11,949
Accrued retirement benefits		114,098			110,302
Regulatory liabilities		204,774			202,131
Other deferred credits and liabilities		66,874			67,495
Total Deferred Credits and Other Liabilities		806,597			787,331
Liabilities Held for Sale (Note 10)		-			30,706
Shareholder's Equity:
Common stock, $3.75 par value, 20,000,000 shares authorized, 1,000 shares issued and outstanding for 2011 and 2010		4			4
Other paid-in capital		1,111,574			1,111,262
Retained deficit		(165,138	)		(135,226	)
Accumulated other comprehensive loss		(669	)		(2,620	)
Total Shareholder's Equity		945,771			973,420
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	3,215,929		$	3,347,022
The accompanying notes are an integral part of the financial statements.

(Concluded)

17

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
	For the Six Months Ended
	June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	20,088		$	28,435
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		53,122			52,889
Deferred taxes and deferred investment tax credit		9,840			6,440
AFUDC-equity		(1,211	)		(1,331	)
Deferred energy		(14,641	)		20,813
Gain on sale of asset		-			(7,575	)
Amortization of other regulatory assets		39,242			13,716
Other, net		6,456			5,493
Changes in certain assets and liabilities:
Accounts receivable		21,518			36,853
Materials, supplies and fuel		(14,388	)		216
Other current assets		4,304			6,181
Accounts payable		2,264			9,775
Accrued retirement benefits		3,796			(1,287	)
Other current liabilities		(4,666	)		(1,396	)
Risk management assets and liabilities		508			1,561
Other deferred assets		(479	)		(1,098	)
Other regulatory assets		(18,096	)		(9,365	)
Other deferred liabilities		(2,468	)		(2,265	)
Net Cash from Operating Activities		105,189			158,055
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(57,553	)		(77,185	)
Proceeds from sale of asset		131,789			14,971
Customer advances for construction		(2,129	)		(2,068	)
Contributions in aid of construction		8,984			1,898
Investments and other property - net		16			(119	)
Net Cash from (used by) Investing Activities		81,107			(62,503	)
CASH FLOWS USED BY FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		-			23,013
Retirement of long-term debt		(15,755	)		(40,958	)
Dividends paid		(104,000	)		(25,000	)
Net Cash used by Financing Activities		(119,755	)		(42,945	)
Net Increase (Decrease) in Cash and Cash Equivalents		66,541			52,607
Beginning Balance in Cash and Cash Equivalents		9,552			14,359
Ending Balance in Cash and Cash Equivalents	$	76,093		$	66,966
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	29,817		$	33,124
Income taxes	$	-		$	12
Significant non-cash transactions:
Accrued construction expenses as of June 30,	$	17,507		$	7,683
The accompanying notes are an integral part of the financial statements.

18

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands, except share amounts)
	Common Stock Shares		Common Stock Amount		Other Paid-in Capital		Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholder's Equity
December 31, 2009		1,000	$	4	$	1,111,260	$	(99,601	)	$	(2,405	)	$	1,009,258
Net Income								28,435						28,435
Change in compensation retirement benefits liability and amortization (net of taxes ($9))											17			17
Dividends Declared								(25,000	)					(25,000	)
June 30, 2010		1,000	$	4	$	1,111,260	$	(96,166	)	$	(2,388	)	$	1,012,710
December 31, 2010		1,000		4		1,111,262		(135,226	)		(2,620	)		973,420
Net Income								20,088						20,088
Tax benefit from stock options exercised						312								312
Change in compensation retirement benefits liability and amortization (net of taxes ($1,051))											1,951			1,951
Dividends Declared								(50,000	)					(50,000	)
June 30, 2011		1,000	$	4	$	1,111,574	$	(165,138	)	$	(669	)	$	945,771
The accompanying notes are an integral part of the financial statements.

19

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.                          SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Pacific Energy Company, NVE Insurance Company, Inc. and Sierra Gas Holding Company.  All intercompany balances and transactions have been eliminated in consolidation.

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

In the opinion of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown.  These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2010 Form 10-K.

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

Consolidations of VIEs

In June 2009, the FASB amended existing guidance related to the Consolidation of VIEs.  NVE and the Utilities adopted this amendment on January 1, 2010.  The amendment no longer allows the scope exception for contracts which an entity was unable to obtain financial information from to be excluded from the primary beneficiary determination.  As a result, NVE and the Utilities will continually perform an analysis to determine whether their variable interests give it controlling financial interest in a VIE which would require consolidation.  This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the following characteristics: a) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.  To identify potential variable interests, management reviewed contracts under leases, long term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests.  However, the Utilities are not the primary beneficiary as defined above, as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.  The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power.  However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism.  As of June 30, 2011, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.

Recent Accounting Standards Updates

Fair Value Measurements and Disclosures

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

20

Other Comprehensive Income

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

NOTE 2.                 SEGMENT INFORMATION

The Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC.  Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC.  Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada.  Other information includes amounts below the quantitative thresholds for separate disclosure.

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

Three Months Ended
June 30, 2011
	NVE Consolidated			NVE Other			NPC Electric		SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues (1)	$	674,931		$	3		$	473,898	$	201,030		$	164,582		$	36,448
Energy Costs:
Fuel for power generation		156,803			-			114,744		42,059			42,059			-
Purchased power		160,308			-			122,408		37,900			37,900			-
Gas purchased for resale		24,984			-			-		24,984			-			24,984
Deferred energy		(8,106	)		-			2,350		(10,456	)		(11,898	)		1,442
Total Energy Costs	$	333,989		$	-		$	239,502	$	94,487		$	68,061		$	26,426
Gross Margin (1)	$	340,942		$	3		$	234,396	$	106,543		$	96,521		$	10,022
Other operating expenses		97,547			925			61,935		34,687
Maintenance		32,186			-			19,325		12,861
Depreciation and amortization		89,606			-			61,913		27,693
Taxes other than income		14,684			39			9,046		5,599
Operating Income (Loss)	$	106,919		$	(961	)	$	82,177	$	25,703

21

Six Months Ended
June 30, 2011
	NVE Consolidated			NVE Other			NPC Electric		SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues (1)	$	1,315,914		$	7		$	863,966	$	451,941		$	343,199		$	108,742
Energy Costs:
Fuel for power generation		303,141			-			215,814		87,327			87,327			-
Purchased power		295,324			-			217,974		77,350			77,350			-
Gas purchased for resale		77,616			-			-		77,616			-			77,616
Deferred energy		(10,058	)		-			9,080		(19,138	)		(23,829	)		4,691
Total Energy Costs	$	666,023		$	-		$	442,868	$	223,155		$	140,848		$	82,307
Gross Margin (1)	$	649,891		$	7		$	421,098	$	228,786		$	202,351		$	26,435
Other operating expenses		203,521			1,582			127,036		74,903
Maintenance		61,948			-			41,662		20,286
Depreciation and amortization		172,708			-			119,586		53,122
Taxes other than income		30,929			202			19,104		11,623
Operating Income (Loss)	$	180,785		$	(1,777	)	$	113,710	$	68,852

Three Months Ended
June 30, 2010
	NVE Consolidated		NVE Other			NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues (1)	$	782,683	$	6		$	539,395	$	243,282	$	202,877	$	40,405
Energy Costs:
Fuel for power generation		181,662		-			132,067		49,595		49,595		-
Purchased power		165,321		-			124,740		40,581		40,581		-
Gas purchased for resale		25,154		-			-		25,154		-		25,154
Deferred energy		54,933		-			39,960		14,973		8,725		6,248
Total Energy Costs	$	427,070	$	-		$	296,767	$	130,303	$	98,901	$	31,402
Gross Margin (1)	$	355,613	$	6		$	242,628	$	112,979	$	103,976	$	9,003
Other operating expenses		101,388		1,082			63,292		37,014
Maintenance		28,860		-			18,219		10,641
Depreciation and amortization		84,696		-			57,654		27,042
Taxes other than income		15,939		48			9,793		6,098
Operating Income (Loss)	$	124,730	$	(1,124	)	$	93,670	$	32,184

22

Six Months Ended
June 30, 2010
	NVE Consolidated		NVE Other			NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues (1)	$	1,497,172	$	14		$	965,194	$	531,964	$	411,539	$	120,425
Energy Costs:
Fuel for power generation		403,281		-			288,182		115,099		115,099		-
Purchased power		272,684		-			195,967		76,717		76,717		-
Gas purchased for resale		90,713		-			-		90,713		-		90,713
Deferred energy		72,499		-			59,423		13,076		7,225		5,851
Total Energy Costs	$	839,177	$	-		$	543,572	$	295,605	$	199,041	$	96,564
Gross Margin (1)	$	657,995	$	14		$	421,622	$	236,359	$	212,498	$	23,861
Other operating expenses		208,014		1,636			130,011		76,367
Maintenance		54,589		-			35,238		19,351
Depreciation and amortization		165,644		-			112,755		52,889
Taxes other than income		32,112		129			19,819		12,164
Operating Income (Loss)	$	197,636	$	(1,751	)	$	123,799	$	75,588

(1) As reported in our 2010 Form 10-K, amounts for REPR are presented net.  As such, revenues and gross margin for the three months ended June 30, 2010 were reduced by $2.7 million, $1.4 million and $1.3 million for NVE, NPC and SPPC, respectively, from that reported in Forms 10-Q/A for the period ended June 30, 2010. Revenues and gross margin for the six months ended June 30, 2010 were reduced by $5.2 million, $2.6 million and $2.6 million for NVE, NPC and SPPC, respectively, from that reported in Forms 10-Q/A for the period ended June 30, 2010. The change in presentation did not affect operating income or net income.

NOTE 3.                      REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 Form 10-K for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy amounts were included in the consolidated balance sheets as of June 30, 2011 (dollars in thousands):

	June 30, 2011
	NVE Total			NPC Electric				SPPC Electric			SPPC Gas
Nevada Deferred Energy
Cumulative Balance requested in 2011 DEAA	$	(331,013	)	$	(186,460	)	(1)	$	(115,602	)	$	(28,951	)
2011 Amortization		104,330			45,355				48,320			10,655
2011 Deferred Energy Over Collections (2)		(100,833	)		(56,708	)			(28,075	)		(16,050	)
Nevada Deferred Energy Balance at June 30, 2011 - Subtotal	$	(327,516	)	$	(197,813	)		$	(95,357	)	$	(34,346	)
Reinstatement of deferred energy (effective 6/07, 10 years)		125,999			125,999				-			-
Total Deferred Energy	$	(201,517	)	$	(71,814	)		$	(95,357	)	$	(34,346	)
Deferred Assets
Deferred energy	$	111,135		$	111,135			$	-		$	-
Current Liabilities
Deferred energy		(312,652	)		(182,949	)			(95,357	)	$	(34,346	)
Total Deferred Energy	$	(201,517	)	$	(71,814	)		$	(95,357	)	$	(34,346	)

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

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     Nevada Power Company and Sierra Pacific Power Company

          Assembly Bill 215

In 2011, the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  The Utilities will still be required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate.  As discussed below, SPPC filed an application to change its quarterly DEAA in July 2011, and NPC expects to file an application late in 2011.

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

             EEIR

In 2009, the Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN.  As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation.  The regulation was adopted by the Legislature on July 22, 2010.  The Utilities account for the effects of such regulation in accordance with FASC 980-605-25, Alternative Revenue Programs.  Accordingly, as of August 1, 2010, the Utilities began recording the amount of additional revenues which are objectively determinable and probable of recovery and are attributable to reduced kWh sales related to energy efficiency programs, prior to their inclusion in rates.

In October 2010, the Utilities filed to set 2011 base rates effective mid 2011 to recover approximately $35.1 million and $7.6 million for NPC and SPPC, respectively, for estimated reduced kWh sales related to our energy efficiency programs.  Annually, thereafter, the Utilities will make a filing in March, to adjust rates and set a clearing rate or EEIR for over or under collected balances, effective in October of the same year.In May 2011, the PUCN issued a final order on the October 2010 filing authorizing increases to the base rates of $14.4 million and $2.6 million for NPC and SPPC, respectively, effective July 1, 2011.  As a result of the May order, for the three months ended June 30, 2011, NPC and SPPC recorded a pre-tax  adjustment to earnings for revenue previously recorded of approximately $4.5 million and $4.1 million, respectively.  As of June 30, 2011, NPC and SPPC have recognized 2011 revenues of approximately $7.4 million and $1 million, respectively, of the authorized EEIR base amounts in accordance with FASC 980-605-25, Alternative Revenue Programs discussed above.

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

   EEPR

In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every 3 years) to recovery through independent annual rate filings.  Accordingly, in their filing made in October 2010, the Utilities have requested to set base rates beginning mid 2011 to recover the 2011 costs of implementing energy efficiency program costs of approximately $71.0 million and $12.1 million for NPC and SPPC, respectively.  In May 2011, the PUCN issued a final order authorizing increases to the base rates of $58.0 million and $9.8 million for NPC and SPPC, respectively, effective July 1, 2011.  Costs accumulated between August 1, 2010 and December 31, 2010 were requested for recovery in the March 2011 DEAA filing with rates effective October 2011. Reference further discussion below at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filing.

      Ely Energy Center

In February 2011, NVE and the Utilities cancelled plans to construct the EEC due to increasing environmental and economic uncertainties.  In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC.  Simultaneously, the Utilities filed a new UEPA application for the construction of a transmission line which was granted in May 2011.  The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $65.5 million as of June 30, 2011.  Management believes the amounts expended through June 30, 2011 are probable of recovery.  In compliance with the SPPC 2010 Electric GRC, SPPC filed a separate application concurrent with the filing of NPC’s GRC filed in June 2011, to determine the reasonableness of the EEC project development costs and propose reclassification of these costs from a deferred debit to a regulatory asset.

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     Nevada Power Company

   NPC 2011 GRC

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

• Increase in general rates by $245.5 million;

• ROE and ROR of 11.25% and 8.66%, respectively;

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

• Authorization to defer collection of approximately $64 million of the requested rate increase as a regulatory asset in order to mitigate the impact on customers.  The remaining requested increase of approximately $181.5, is expected to be effective on January 1, 2012, is approximately equal to revenue requirement decreases associated with fuel and other items, also expected to be effective  on January 1, 2012.

A decision on NPC’s 2011 GRC is expected in December 2011.

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

In March 2011, NPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR).  The recoveries requested in this filing result in an overall change in revenue requirement of approximately $73.2 million.  Hearings are scheduled for mid-August 2011.  The March 2011 application includes the following (dollars in millions):

		Requested and
	Anticipated	Amended				Present				$ Change in
	Effective	Revenue				Revenue				Revenue
	Date	Requirement				Requirement				Requirement
Revenue Requirement Subject To Change:
DEAA	Jan. 2012	$	(186.5	)		$	(101.0	)		$	(85.5	)
REPR	Oct. 2011		9.0				29.9				(20.9	)
TRED	Oct. 2011		14.6				16.3				(1.7	)
EEPR Base	Oct. 2011		58.0		(1)		58.0		(1)		-
EEPR Amortization	Oct. 2011		22.8				-				22.8
EEIR Base	Oct. 2011		14.4		(1)		14.4		(1)		-
EEIR Amortization	Oct. 2011		12.1		(2)		-				12.1
Total Revenue Requirement		$	(55.6	)		$	17.6			$	(73.2	)

(1)

Reflects impact of adjustments ordered in the May 2011 PUCN Docket No. 10-10024, filed in October 2010 and effective July 1, 2011.

(2)

Amount represents proposed EEIR amortization rates as originally filed.  In accordance with Alternative Revenue Accounting, NPC has recognized approximately $4.8 million of this amount in revenues pertaining to 2010.  Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, NPC does not expect to record further revenue from this rate request; however, NPC does expect to collect approximately $4.8 million from its customers.

  NPC Harry Allen Regulatory Asset Filing

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

     Sierra Pacific Power Company

         SPPC 2011 Nevada Electric Quarterly DEAA Application

As a result of Assembly Bill 215 discussed above, in July 2011, SPPC filed an application with the PUCN for authorization to make quarterly adjustments to the electric DEAA.  Quarterly changes to the electric DEAA should produce more frequent, but more gradual changes in the electric DEAA and should avoid the accumulation of significant credit or debit balances.  SPPC requested the first quarterly adjustment to the electric DEAA to become effective on January 1, 2012.

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      SPPC 2011 Nevada Gas Quarterly DEAA Application

As a result of Assembly Bill 215 discussed above, in July 2011, SPPC filed an application with the PUCN for authorization to make quarterly adjustments to the gas DEAA.  Quarterly changes to the gas DEAA should produce more frequent, but more gradual changes in the gas DEAA and should avoid the accumulation of significant credit or debit balances.  SPPC requested the first quarterly adjustment to the gas DEAA to become effective on January 1, 2012.

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

In March 2011, SPPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR).  The recoveries requested in this filing result in an overall decrease in revenue requirement of approximately $4.4 million.  Hearings are scheduled for mid-August 2011.  The March 2011 application includes the following (dollars in millions):

		Requested and
	Anticipated	Amended				Present				$ Change in
	Effective	Revenue				Revenue				Revenue
	Date	Requirement				Requirement				Requirement
Revenue Requirement Subject To Change:
DEAA	Jan. 2012	$	(115.6	)		$	(99.5	)		$	(16.1	)
REPR	Oct. 2011		38.1				36.6				1.5
TRED	Oct. 2011		5.9				7.9				(2.0	)
EEPR Base	Oct. 2011		9.8		(1)		9.8		(1)		-
EEPR Amortization	Oct. 2011		4.7				-				4.7
EEIR Base	Oct. 2011		2.6		(1)		2.6		(1)		-
EEIR Amortization	Oct. 2011		7.5		(2)		-				7.5
Total Revenue Requirement		$	(47.0	)		$	(42.6	)		$	(4.4	)

(1)

Reflects impact of adjustments ordered in the May 2011 PUCN Docket No. 10-10025, filed in October 2010 and effective July 1, 2011.

(2)

Amount represents proposed EEIR amortization rates as originally filed.  In accordance with Alternative Revenue Accounting, SPPC has recognized approximately $0.5 million of this amount in revenues pertaining to 2010.  Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, SPPC does not expect to record further revenue from this rate request; however, SPPC does expect to collect approximately $0.5 million from their customers.

         SPPC 2011 Nevada Gas DEAA

In March 2011, SPPC filed an application to create a new DEAA rate to refund over-collected gas costs and to establish a new STPR (Solar Thermal Prospective Rate) to recover a legislatively mandated solar thermal program.  Hearings are scheduled for August 2011.  The March 2011 application includes the following (dollars in millions):

	Anticipated	Requested			Present			$ Change in
	Effective	Revenue			Revenue			Revenue
	Date	Requirement			Requirement			Requirement
Revenue Requirement Subject To Change:
DEAA	Jan. 2012	$	(29.0	)	$	(16.7	)	$	(12.3	)
STPR	Oct. 2011		0.3			-			0.3
Total Revenue Requirement		$	(28.7	)	$	(16.7	)	$	(12.0	)

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NOTE 4.                      LONG-TERM DEBT

   Maturities of Long-Term Debt

As of June 30, 2011, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

	NVE Consolidated			NVE Holding Co.			NPC			SPPC
2011(1)	$	2,188		$	-		$	2,188		$	-
2012		134,822			-			134,822			-
2013		395,405			-			145,405			250,000
2014		128,513			-			128,513			-
2015		251,039			-			251,039			-
Total Debt 2011-2015		911,967			-			661,967			250,000
Thereafter		4,388,183			506,500			2,965,266			916,417
Total Debt Before Unamortized Premium (Discount)		5,300,150			506,500			3,627,233			1,166,417
Unamortized Premium Discount Amount		(12,569	)		(1	)		(26,202	)		13,634
Total Debt	$	5,287,581		$	506,499		$	3,601,031		$	1,180,051

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

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

Financing Transactions

   Nevada Power Company

5.45% General and Refunding Mortgage Notes, Series Y

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

NOTE 5.                       FAIR VALUE OF FINANCIAL INSTRUMENTS

The June 30, 2011 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments.

The total fair value of NVE’s consolidated long-term debt at June 30, 2011, is estimated to be $5.8 billion based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities.  The total fair value was estimated to be $5.7 billion as of December 31, 2010.

The total fair value of NPC’s consolidated long-term debt at June 30, 2011, is estimated to be $4.0 billion based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities.  The total fair value was estimated to be $3.9 billion at December 31, 2010.

The total fair value of SPPC’s consolidated long-term debt at June 30, 2011, is estimated to be $1.3 billion based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities.  The total fair value was estimated to be $1.3 billion as of December 31, 2010.

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NOTE 6.                       DERIVATIVES AND HEDGING ACTIVITIES

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

Commodity Risk

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

Interest Rate Risk

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

Determination of Fair Value

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

Option Premiums
	June 30, 2011								December 31, 2010
	NVE			NPC			SPPC		NVE			NPC			SPPC
Current Assets	$	0.4		$	0.4		$	-	$	1.9		$	1.4		$	0.5
Current Liabilities	$	(0.4	)	$	(0.4	)	$	-	$	(0.4	)	$	(0.4	)	$	-

Forwards and swaps are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value.  Options are valued based on an income approach using an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option volatility rates.  The determination of the fair value for derivative instruments not only includes counterparty risk, but also the impact of NVE and the Utilities’ nonperformance risk on their liabilities, which as of June 30, 2011, had an immaterial impact to the fair value of their derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the consolidated balance sheets of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria as required by the Derivatives and Hedging Topic of the FASC.  Due to regulatory accounting treatment under

28

which the utilities operate, regulatory assets and liabilities are established to the extent that derivative gains and losses are recoverable or payable through future rates, once realized.  This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on derivative transactions until the period of settlement (dollars in millions):

	June 30, 2011									December 31, 2010
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC
Risk management assets - current (1)	$	-		$	-		$	-		$	2.1		$	2.1		$	-
Risk management liabilities- current (1)		5.0			4.1			0.9			32.9			22.4			10.5
Risk management regulatory assets/liabilities – net	$	(5.0	)	$	(4.1	)	$	(0.9	)	$	(30.8	)	$	(20.3	)	$	(10.5	)

(1) When amount is negative it represents a risk management regulatory asset, when positive it represents a risk management regulatory liability.  For the three months ended June 30, 2011, NVE, NPC and SPPC would have recorded cumulative gains of $3.2 million, $2.6 and $0.6 million, respectively, and for the six months ended June 30, 2011 NVE, NPC and SPPC would have recorded gains of $25.8 million, $16.2 and $9.6 million, respectively.  However, as permitted by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains and losses, which are included in the risk management regulatory asset amounts above.

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate.  The Utilities cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in market prices.  Risk management liabilities decreased as of June 30, 2011 as compared to December 31, 2010, due to settlements of derivative contracts and the suspension of the Utilities’ hedging program as of October 2009.

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

June 30, 2011

December 31, 2010

Commodity Volume (MMBTU)

Commodity Volume (MMBTU)

NVE

NPC

SPPC

NVE

NPC

SPPC

Commodity volume liabilities- current (1)

3.5

3.0

0.5

18.1

12.9

5.2

(1) The change in commodity volumes at June 30, 2011, as compared to December 31, 2010, is primarily due to the suspension of the Utilities’ hedging program as of October 2009.  As such, the Utilities’ exposure to mark-to-market hedging transactions has declined. 

NOTE 7.                      RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities.  NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location.  Certain grandfathered and union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.   A summary of the components of net periodic pension and other postretirement costs for the three and six months ended June 30 follows.  This summary is based on a December 31, measurement date (dollars in thousands):

29

NVE
	Pension Benefits						Other Postretirement Benefits
	For the three months ended June 30,						For the three months ended June 30,
	2011			2010			2011			2010
Service cost	$	4,607		$	4,727		$	653		$	617
Interest cost		10,169			10,718			2,090			2,184
Expected return on plan assets		(12,192	)		(11,069	)		(1,596	)		(1,556	)
Amortization of prior service cost		(738	)		(448	)		(987	)		(972	)
Amortization of net loss		4,155			3,777			1,083			1,085
Net periodic benefit cost	$	6,001		$	7,705		$	1,243		$	1,358
	Pension Benefits						Other Postretirement Benefits
	For the six months ended June 30,						For the six months ended June 30,
		2011			2010			2011			2010
Service cost	$	9,213		$	9,455		$	1,306		$	1,233
Interest cost		20,338			21,436			4,180			4,368
Expected return on plan assets		(24,383	)		(22,138	)		(3,193	)		(3,111	)
Amortization of prior service cost		(1,476	)		(897	)		(1,973	)		(1,945	)
Amortization of net loss		8,310			7,553			2,166			2,171
Net periodic benefit cost	$	12,002		$	15,409		$	2,486		$	2,716
The average percentage of NVE net periodic costs capitalized during 2011 and 2010 was 32.77% and 33.58% respectively.

NPC
	Pension Benefits						Other Postretirement Benefits
	For the three months ended June 30,						For the three months ended June 30,
	2011			2010			2011			2010
Service cost	$	2,445		$	2,392		$	363		$	353
Interest cost		4,880			5,023			615			619
Expected return on plan assets		(6,169	)		(5,362	)		(590	)		(567	)
Amortization of prior service cost		(470	)		(433	)		229			236
Amortization of net loss		1,690			1,764			302			300
Net periodic benefit cost	$	2,376		$	3,384		$	919		$	941
	Pension Benefits						Other Postretirement Benefits
	For the six months ended June 30,						For the six months ended June 30,
		2011			2010			2011			2010
Service cost	$	4,891		$	4,784		$	727		$	707
Interest cost		9,760			10,046			1,230			1,237
Expected return on plan assets		(12,339	)		(10,724	)		(1,180	)		(1,135	)
Amortization of prior service cost		(939	)		(866	)		458			473
Amortization of net loss		3,379			3,528			604			599
Net periodic benefit cost	$	4,752		$	6,768		$	1,839		$	1,881
The average percentage of NPC net periodic costs capitalized during 2011 and 2010 was 37.32% and 35.71% respectively.

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SPPC
	Pension Benefits						Other Postretirement Benefits
	For the three months ended June 30,						For the three months ended June 30,
	2011			2010			2011			2010
Service cost	$	1,840		$	2,004		$	271		$	245
Interest cost		5,013			5,389			1,457			1,547
Expected return on plan assets		(5,741	)		(5,431	)		(976	)		(961	)
Amortization of prior service cost		(277	)		(26	)		(1,219	)		(1,213	)
Amortization of net loss		2,412			1,969			773			777
Net periodic benefit cost	$	3,247		$	3,905		$	306		$	395
	Pension Benefits						Other Postretirement Benefits
	For the six months ended June 30,						For the six months ended June 30,
		2011			2010			2011			2010
Service cost	$	3,680		$	4,008		$	543		$	489
Interest cost		10,025			10,779			2,915			3,094
Expected return on plan assets		(11,482	)		(10,862	)		(1,952	)		(1,922	)
Amortization of prior service cost		(554	)		(52	)		(2,439	)		(2,426	)
Amortization of net loss		4,824			3,938			1,546			1,554
Net periodic benefit cost	$	6,493		$	7,811		$	613		$	789
The average percentage of SPPC net periodic costs capitalized during 2011 and 2010 was 30.22% and 34.55% respectively.

During the six months ended June 30, 2011, SPPC did not make any contributions to the pension or other postretirement benefits plans.  At the present time, it is not anticipated that additional funding will be required for either plan in 2011 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2011 assumptions funding levels similar to the 2010 funding.  The amounts to be contributed in 2011 may change subject to market conditions.

NOTE 8.                       COMMITMENTS AND CONTINGENCIES

Environmental

   NPC and SPPC

Regional Haze Rule Update

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

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

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

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   NPC

      NEICO

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

   SPPC

      Valmy Generating Station

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

Other Environmental Matters

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

Litigation Contingencies

   NPC and SPPC

      Peabody Western Coal Company – Royalty Claim

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

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

The Navajo Joint Owners were first served in the Missouri lawsuit in January 2005.  The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners.  In July 2008, the Court dismissed all counts against NPC, two without prejudice to their possible refiling at a later date.  NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station.  The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted.  Initially, the DC Lawsuit sought $600 million in damages, treble damages and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease.  In July 2001, the U.S. District Court dismissed all claims against Salt River.   In April 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages.  Factual discovery was completed in October 2010, after which the parties engaged in settlement discussions. In April 2011, SCE indicated that it reached a settlement in the DC Lawsuit in principle. On August 1, 2011, the Navajo Nation, Peabody, Salt River and SCE executed a written settlement agreement in return for dismissal of all claims by the Navajo Nation. Salt River has asked that the Navajo Joint

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Owners, including NPC, contribute towards the settlement based on its 11% percent ownership stake in the Navajo plant. NPC has agreed to pay Salt River the requested contribution, which will not have a material impact on the financial statements.  SCE has asked that the Mohave Joint Owners, including NPC, contribute towards the settlement based upon their ownership stake in the Mohave plant. NPC has not agreed to pay SCE the requested contribution. Management continues to assess to what extent it should reimburse SCE, but does not believe the impact of such assessment will be material to NPC at this time.

   SPPC

      Farad Dam

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

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance 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 has requested the court to reconsider the cash value to reflect rebuild costs and the Insurers opposed.   The Insurers time to file an appeal on the Court’s decision had been suspended pending the Court’s determination on the cash value reconsideration.  On July 10, 2009, the District Court declined SPPC’s request to reconsider the cash value and further ordered that the three year period to replace the dam commences as of July 10th. In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the Ninth Circuit. Subsequently, in August 2009, the Insurers appealed the District Court’s insurance coverage decision with the Ninth Circuit.  The Ninth Circuit heard arguments on the appeal in November 2010 and further asked that the parties consider mediation settlement proceedings. In January 2011, the parties, including TMWA, agreed to engage in mediation settlement discussions. Mediation was not successful, and the case was returned to the active docket for decision by the Ninth Circuit. On June 15, 2011, the parties filed supplemental briefs concerning the cash value determination and the replacement cost of the dam. A decision is expected in the third or fourth quarter of 2011.

Other Legal Matters

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

Other Commitments

   NPC and SPPC

      ON Line TUA

During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South.  Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen Generating Station on the NPC system by late 2012.  The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1.  Under the terms of the TUA, NVE’s future lease payments are adjusted for construction costs, including cost overruns; therefore, for accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of June 30, 2011, NVE has capitalized construction costs associated with GBT’s 75% interest of approximately $51.5 million, or $50.1 and $1.4 million at NPC and SPPC, respectively, in CWIP with a corresponding credit to other deferred liabilities.

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NOTE 9.                      EARNINGS PER SHARE (NVE)

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Basic EPS
Numerator ($000)
Net Income	$	12,888	$	36,946	$	15,218	$	35,225
Denominator(1)
Weighted average number of common shares outstanding		235,867,068		234,995,083		235,697,687		234,927,239
Per Share Amounts
Net Income per share - basic	$	0.05	$	0.16	$	0.06	$	0.15
Diluted EPS
Numerator ($000)
Net Income	$	12,888	$	36,946	$	15,218	$	35,225
Denominator(1)
Weighted average number of shares outstanding before dilution		235,867,068		234,995,083		235,697,687		234,927,239
Stock options		42,199		29,132		37,799		28,241
Non-Employee Director stock plan		122,737		135,436		143,319		131,690
Employee stock purchase plan		2,528		3,538		3,551		4,548
Restricted Shares		124,116		66,062		112,678		60,177
Performance Shares		1,119,898		905,198		1,032,622		813,557
Diluted Weighted Average Number of Shares		237,278,546		236,134,449		237,027,656		235,965,452
Per Share Amounts
Net income per share - diluted	$	0.05	$	0.16	$	0.06	$	0.15

(1) The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for all periods.  If the conditions for conversion were met under this plan, 572,957 and 577,357 shares would be included for the three and six months ended June 30, 2011, and 708,031 and 711,330 would be included for the three and six months ended June 30, 2010, respectively.

NOTE 10.                      ASSETS HELD FOR SALE

Sale of California Electric Distribution and Generation Assets

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

NOTE 11.                      DIVIDENDS

Dividends

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

Declaration Date	Amount	Payable Date	Shareholders of Record Date
May 3, 2011	$0.12	June 22, 2011	June 7, 2011
August 4, 2011	$0.12	September 21, 2011	September 6, 2011

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

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

                          RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

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

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

(1)   economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, a decrease in tourism, particularly in Southern Nevada, and cancelled or deferred hotel construction projects, each of which affect customer growth, customer collections, customer demand and usage patterns;

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

(3)   unfavorable or untimely rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, including, but not limited to GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, and energy efficiency recovery programs relating to the EEIR and EEPR;

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

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

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

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

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

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

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

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

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

(13)   depending on their needs and analysis of the existing portfolio, whether the Utilities can procure and/or obtain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada;

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

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

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

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

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

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

(20) the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general; including the impact of acts of terrorism or vandalism that damage or disrupt information technology and systems owned by the Utilities, or third parties on which the Utilities rely;

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

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

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

 Other factors and assumptions not identified above may also have been involved in deriving forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to

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differ materially from those projected.  NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

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

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

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

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

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

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

NOTE REGARDING STATISTICAL DATA

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

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EXECUTIVE OVERVIEW

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

• Critical Accounting Policies and Estimates:

• Recent Pronouncements

• For each of NVE, NPC and SPPC:

• Results of Operations

• Analysis of  Cash Flows

• Liquidity and Capital Resources

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

NVE recognized net income of $12.9 million and $15.2 million for the three and six months ended June 30, 2011, respectively, compared to net income of $36.9 million and $35.2 million for the three and six months ended June 30, 2010, respectively.   The decrease in net income for the three and six months ended June 30, 2011 compared to the same period in 2010 is primarily due to a decrease in gross margin, the gain on sale of Independence Lake recognized in 2010, increased depreciation expense and a decrease in AFUDC due to the addition of the Harry Allen Generating Station, which is not currently included in rates, and an adjustment for revenue recorded in 2010, as a result of the PUCN’s final decision on the EEIR rate.  Partially offsetting this decrease was the implementation of the EEIR rate, reflected in gross margin, which became effective August 1, 2010, (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements) and a decrease in operating expenses.

The Utilities are regulated by the PUCN.  The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission.  The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.  As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources.  NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning.  SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter.  The variations in energy usage are primarily due to varying weather, customer growth and other energy usage patterns, including DSM programs and energy efficiency and conservation measures, which necessitate a continual balancing of loads and resources and purchases and sales of energy under short and long-term contracts.  As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities.  Additionally, the timely recovery of purchased power and fuel costs, and other costs, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

Future Challenges

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

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

• customer growth;

• customer  usage;

• revenues;

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

• load factors;

• future capital projects and capital requirements;

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

• our liquidity and ability to access capital markets;

• collections on accounts receivable; and

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 •  counterparty risk.

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

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

• Full and timely rate recovery of costs.

  Economic Conditions

In NPC’s service territory, which consists primarily of Las Vegas, key economic indicators, as outlined below, show modest improvement:

• Unemployment in Las Vegas was at 13.8% in June 2011, down from 15.3% a year ago; however, much of the decline is a result of workers exiting the labor force;

• In southern Nevada, construction activity, another leading indicator, has experienced a decrease in the number of commercial permits while residential permits have remained relatively unchanged;

• Construction employment has decreased 15.8% as of May 2011, compared to May 2010;

• As of April 2011, taxable sales have decreased 0.9%  from a year ago;

• As of May 2011, gaming revenues have increased 19.4% from a year ago;

• As of May 2011, visitor volume increased 2.9% from a year ago; and

• As of May 2011, the hotel/motel occupancy rate in Las Vegas has increased approximately 3.6% from a year ago.

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

• Unemployment in Washoe County was at 13.0% in June 2011, down from 14.1% a year ago; however, much of the decline is a result of workers exiting the labor force;

• Construction employment increased 1.0 % as of May 2011, compared to May 2010;

• As of April 2011, taxable sales increased 10.2% compared to a year ago; and

• As of May 2011, gaming revenues decreased 6.6% compared to a year ago.

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.  Gaming properties in southern Nevada are experiencing financial problems, including difficulties meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases.

The Portfolio Standard

The Portfolio Standard as set forth by Nevada law requires a specific percentage of an electric service provider’s total retail energy sales be obtained from renewable resources.  Renewables include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects.  In 2011 and 2012, the Utilities are required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables.  Currently, the Portfolio Standard increases to 18% for 2013 and 2014 and reaches 20% in 2015 after which it increases to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond.  Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources until 2016 when a minimum of 6% must be solar.  The Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard.  Under this provision, a PEC is created for each kWh of energy conserved by qualified energy efficiency programs.  In addition, energy saved during peak demand hours earns double the PECs for each kWh of energy conserved.  After the DSM percentage allowance is fully utilized, NVE’s strategy is to assess economic conditions and potential rate impacts in pursuing the implementation of cost effective DSM programs needed to achieve future Portfolio Standard requirements.  The successful execution of the three part strategy, as discussed below, will be critical to our ability to meet the Portfolio Standard.

Three Part Strategy

The three part strategy which began in 2007 to manage resources against our load includes (1) encouraging energy efficiency and conservation programs, (2) the purchase and development of renewable energy projects, and (3) construction of generating facilities in an effort to reduce our reliance on purchased power and expansion of transmission capability.

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      Energy Efficiency and Conservation Programs

As stated above, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard.  As such, NVE remains committed to investing in such programs that qualify toward the Portfolio Standard, reduce our peak load, especially during peak periods, and are cost-effective.  NVE’s current 2011 budget includes approximately $67.5 million for energy efficiency and conservation programs.  Furthermore, the Utilities will continue with the implementation of NV Energize which will provide NVE with the Smart Grid infrastructure necessary to: (1) enable the achievement of metering and customer service operating savings; (2) enable the expansion of demand response and energy efficiency benefits; and (3) provide customers better information to help manage their energy usage.

       Purchase and Development of Renewable Energy Resources

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

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

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

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

ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.  The Joint Project consists of two phases.  In Phase 1 of the Joint Project, the parties would complete construction of an initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen Generating Station on the NPC system by late 2012.  Under the Joint Project, the Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. The Utilities 25% interest in Phase 1 of the Joint Project, which approximates $127 million, will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of Phase 1, which is estimated to be approximately 600 MW.  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one extending from Robinson Summit north to Midpoint, Idaho, and the other commencing at the Harry Allen Generating Station and interconnecting south to the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.  However, NPC and SPPC would have rights to additional transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the complete path).

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

 Full and Timely Rate Recovery of Costs

The Utilities are required to file rate cases every three years to adjust general rates in order to recover their cost of service and return on investment.  The frequency of these filings is designed to more closely align earned returns with those allowed by regulators.  In addition, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement.  Historically, resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes.  Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases.  The Utilities remain focused on communicating with regulators the necessity of investments to better serve our customers, the prudency of the costs incurred, and the importance of a reasonable return on investment for our shareholders.  NPC’s GRC was filed in June 2011, with new rates to become effective January 1, 2012.  A

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decision on the rate case is expected in late 2011.  One of the major elements in this GRC will be the inclusion in rate base of the new 500 MW (nominally rated) combined cycle natural gas generators at the site of the existing Harry Allen Generating Station, which was placed in service during the second quarter 2011.    NPC’s investment in this facility (including AFUDC) as of June 30, 2011 was approximately $700 million. Management cannot predict future decisions on our rate cases, but believes the regulatory process, described above, coupled with prudent management provides a reasonable basis for the recovery of our investments.

2011 Goals

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

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

• Building a sustainable foundation for future requirements by:

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

• Continued investment in energy efficiency and conservation programs;

• The purchase and development of cost effective renewable energy projects;

• Construction of ON Line;

• Optimizing generating assets; and

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

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later.  The holding company’s (stand alone) operating results included approximately $16.7 million and $19.3 million of interest costs for the six months ended June 30, 2011 and 2010, respectively.

As of June 30, 2011, NPC had paid $25 million in dividends to NVE and SPPC had paid $104 million in dividends to NVE.

On August 4, 2011, NPC and SPPC declared dividends to NVE of $40 million and $10 million, respectively.

Other Subsidiaries

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

ANALYSIS OF CASH FLOWS

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

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

Cash Used By Investing Activities. The decrease in cash used by investing activities was primarily due to the receipt of proceeds from the sale of California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements, the decrease in construction activity related to the Harry Allen Generating Station which was placed in service in May 2011 and a decrease in general construction for infrastructure.

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Cash Used By Financing Activities. Cash from financing activities decreased primarily due to a reduction in draws on the Utilities’ revolving credit facilities, the payment of NPC’s $350 million aggregate principal amount of 8.25% General and Refunding Mortgage Notes, which were partially paid by proceeds from the issuance of the NPC’s $250 million 5.45% General and Refunding Mortgage Notes and a draw on the credit facility.  Also contributing to the decrease was the settlement payment of the interest rate swap agreement as discussed in Note 4, Long Term Debt of the Condensed Notes to Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC.  The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.  Available liquidity as of June 30, 2011 was as follows (in millions):

Available Liquidity as of June 30, 2011 (in millions)
	NVE		NPC			SPPC
Cash and Cash Equivalents	$	5.2	$	26.3		$	76.1
Balance available on Revolving Credit Facilities (1)		N/A		445.6			237.5
Less reduction for hedging transactions (2)		-		(4.5	)		(0.9	)
	$	5.2	$	467.4		$	312.7

(1)	As of August 3, 2011, NPC and SPPC had approximately $452.6million and $236.7million available under their revolving credit facilities, which includes reductions in availability for hedging transactions and letters of credits,  as discussed further under NPC’s and SPPC’s Financing Transactions.
(2)	Reduction for hedging transactions reflects balances as of May 31, 2011.

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

NVE and the Utilities have no significant debt maturities remaining in 2011; however, NPC’s $130 million 6.50% General and Refunding Mortgage Notes, Series I, will mature on April 15, 2012.  In addition, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected in late 2012.

NVE and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds and the use of their revolving credit facilities.    Furthermore, in order to fund long-term capital requirements and maturing debt obligations, NVE and the Utilities will use a combination of internally generated funds, the Utilities’ revolving credit facilities, the issuance of long-term debt and/or equity and, in the case of the Utilities, capital contributions from NVE.  However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel, purchased power and operating costs in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less.  In order to maintain sufficient liquidity, NVE and the Utilities may be required to delay capital expenditures (discussed in the 2010 Form 10-K), re-finance debt or issue equity at NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities’ utilization of their revolving credit facilities may be limited.  Additionally, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

As of August 5, 2011, NVE has approximately $16.3 million payable of debt service obligations remaining for 2011, which it intends to pay through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries, below).  On January 4, 2011, NVE contributed $54 million in capital to NPC.  On August 4, 2011, NPC and SPPC declared dividends payable to NVE of $40 million and $10 million, respectively. 

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

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

Factors Affecting Liquidity

   Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1.  Under this covenant restriction, as of June 30, 2011, NVE (consolidated) would be allowed to incur up to $2.0 billion of additional indebtedness, assuming an interest rate of 7%.  The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.

Notwithstanding this restriction, under the terms of the debt, NPC and SPPC would still be permitted to incur a combined total of up to $750 million in indebtedness and letters of credit under their respective revolving credit facilities.  As of June 30, 2011, the combined total outstanding indebtedness and letters of credit under their respective revolving credit facilities was approximately $167 million.  See NPC’s and SPPC’s Ability to Issue Debt sections for further discussion of the Utilities’ limitations on ability to issue debt.

If the applicable series of NVE 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 NVE Notes remain investment grade rated by both Moody’s and S&P (see Credit Ratings below).

   Effect of Holding Company Structure

As of June 30, 2011, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: $191.5 million of its unsecured 6.75% Senior Notes due 2017; and $315 million of its unsecured 6.25% Senior Notes due 2020.

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors.  Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

As of June 30, 2011, NVE, NPC, SPPC and their subsidiaries had approximately $5.3 billion of debt and other obligations outstanding, consisting of approximately $3.6 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $507 million of debt at the holding company and other subsidiaries.  Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

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

   Dividends from Subsidiaries

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

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

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   Credit Ratings

The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt.  NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P.   On March 11, 2011, S&P upgraded NVE’s senior unsecured debt to BB+.  On May 10, 2011, Moody’s upgraded NVE’s senior unsecured debt to Ba2.  As of June 30, 2011, the ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
NVE	Sr. Unsecured Debt	BB	Ba2	BB+
NPC	Sr. Secured Debt	BBB*	Baa2*	BBB*
SPPC	Sr. Secured Debt	BBB*	Baa2*	BBB*

*Investment grade

(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

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

   Energy Supplier Matters

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

Under these contracts, a material adverse change, which includes a credit rating downgrade of NPC and SPPC, may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event, giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  The net mark-to-market value as of June 30, 2011 for all suppliers continuing to provide power under a WSPP agreement would approximate a $49.8 million payment or obligation to NPC.  No amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.  Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.   

Gas transmission service is secured under FERC Tariffs or custom agreements.  These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.  NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of June 30, 2011, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $30.7 million.  Of this amount,

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approximately $23.0 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

   Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts.  As discussed under NPC’s and SPPC’s Financing Transactions, the Utilities shall reduce their availability under the Utilities’ revolving credit facilities for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities.  The calculation of NPC’s and SPPC’s negative mark-to-market exposure as of May 31, 2011 was approximately $4.5 million and $0.9 million, respectively, which amount was in effect for borrowings during the month of June 2011. Currently, the Utilities only have hedging transactions with counterparties who are also lenders on the revolving credit facilities; however, future transactions executed with non-lenders may require the Utilities to post cash collateral in the event of a credit rating downgrade.  Finally, in October 2009, the Utilities suspended their hedging program, and as such, expect their exposure to negative mark-to-market hedging transactions to continue to decline.

   Cross Default Provisions

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

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of approximately $16.1 million during the three months ended June 30, 2011, compared to net income of approximately $29.8million for the same period in 2010.  During the six months ended June 30, 2011, NPC recognized net income of approximately $7.0 million compared to a net income of approximately $17.5 million for the same period in 2010.

During the six months ended June 30, 2011, NPC paid $25 million in dividends to NVE, and on August 4, 2011, NPC declared a dividend to NVE of approximately $40 million. 

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

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which NPC calculates as operating revenues less energy costs, provides a measure of income available to support the other operating expenses of NPC.  For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Operating Revenues:	$	473,898	$	539,395		-12.1	%	$	863,966	$	965,194		-10.5	%
Energy Costs:
Fuel for power generation		114,744		132,067		-13.1	%		215,814		288,182		-25.1	%
Purchased power		122,408		124,740		-1.9	%		217,974		195,967		11.2	%
Deferred energy		2,350		39,960		-94.1	%		9,080		59,423		-84.7	%
	$	239,502	$	296,767		-19.3	%	$	442,868	$	543,572		-18.5	%
Gross Margin	$	234,396	$	242,628		-3.4	%	$	421,098	$	421,622		-0.1	%

Gross margin decreased for both the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to a decrease in residential and commercial usage primarily due to milder weather.  Partially offsetting this decrease was the implementation of the EEIR rate, which became effective August 1, 2010 (see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements) and a slight increase in growth for residential and commercial classes.

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

Operating Revenue

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Operating Revenues:
Residential	$	212,580	$	241,768		-12.1	%	$	397,553	$	437,934		-9.2	%
Commercial		100,455		113,504		-11.5	%		186,312		207,522		-10.2	%
Industrial		145,420		168,186		-13.5	%		248,895		287,367		-13.4	%
Retail  revenues		458,455		523,458		-12.4	%		832,760		932,823		-10.7	%
Other		15,443		15,937		-3.1	%		31,206		32,371		-3.6	%
Total Operating Revenues	$	473,898	$	539,395		-12.1	%	$	863,966	$	965,194		-10.5	%
Retail sales in thousands of MWhs		4,881		4,960		-1.6	%		9,021		9,047		-0.3	%
Average retail revenue per MWh	$	93.93	$	105.54		-11.0	%	$	92.31	$	103.11		-10.5	%

NPC’s retail revenues decreased for the three and six months ended June 30, 2011, as compared to the same period in 2010 primarily due to decreased energy rates from NPC’s various BTER quarterly updates, the annual deferred energy case effective October 1, 2010 and the expiration of the Western Energy Crisis Amortization rate on May 1, 2010 (See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2010 Form 10-K). Residential retail revenues decreased further due to decreases in customer usage resulting from lower temperatures in June 2011. These decreases were partially offset by EEIR revenue, effective August 1, 2010 (See Note 3, Regulatory Actions, of the Condensed Notes to the Financial Statements and in the 2010 Form 10-K). For the three and six months ended June 30, 2011, the average number of residential and commercial customers increased by 1.1% and 0.4%, respectively.  For the three months and six months ended June 30, 2011, industrial customers decreased by 1.0%, and 1.1%, respectively compared to the same period in the prior year.

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Electric Operating Revenues – Other decreased for the three and six months ended June 30, 2011, compared to the same period in 2010 primarily due to decreased rates.

Energy Costs

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

• Weather

• Generation efficiency

• Plant outages

• Total system demand

• Resource constraints

• Transmission constraints

• Natural gas constraints

• Long-term contracts

• Mandated power purchases; and

• Volatility of commodity prices

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Energy Costs
Fuel for power generation	$	114,744	$	132,067		-13.1	%	$	215,814	$	288,182		-25.1	%
Purchased power		122,408		124,740		-1.9	%		217,974		195,967		11.2	%
Energy Costs	$	237,152	$	256,807		-7.7	%	$	433,788	$	484,149		-10.4	%
MWhs
MWhs Generated (in thousands)		3,487		3,699		-5.7	%		6,260		7,130		-12.2	%
Purchased Power (in thousands)		1,718		1,550		10.8	%		3,301		2,407		37.1	%
Total MWhs		5,205		5,249		-0.8	%		9,561		9,537		0.3	%
Average cost per MWh
Average fuel cost per MWh of Generated Power	$	32.91	$	35.70		-7.8	%	$	34.48	$	40.42		-14.7	%
Average cost per MWh of Purchased Power	$	71.25	$	80.48		-11.5	%	$	66.03	$	81.42		-18.9	%
Average total cost per MWh	$	45.56	$	48.92		-6.9	%	$	45.37	$	50.77		-10.6	%

Energy Costs decreased for the three and six months ended June 30, 2011, compared to the same period in 2010 primarily due to a decrease in hedging costs. Volume for the three and six months ended June 30, 2011 remained stable due to cooler weather. The average cost per MWh for energy costs decreased primarily due to decreased hedging costs and lower natural gas prices.

• Fuel for power generation costs decreased for the three and six months ended June 30, 2011 primarily due to a decrease in hedging costs and a decrease in volume. Volume decreased for the three and six months ended June 30, 2011 primarily due to outages within the generation fleet.  The average price per MWh decreased for the three and six months primarily due to a decrease in hedging costs and for the six months period a decrease in natural gas costs. In May 2011, the expansion at the Harry Allen Generating station became commercially operable.  As a result, in future periods, NPC expects that generated MWhs will increase.

• Purchased power costs decreased for the three months ended June 30, 2011 primarily due to a decrease in hedging costs related to tolling and a decrease in the cost of purchased power partially offset by a decrease in pricing for off system sales.  For the six months ended June 30, 2011 purchased power costs increased primarily due to an increase in volume.  For the three months ended and the six months ended June 30, 20111 the average cost per MWh decreased primarily due to a decrease in the cost of purchased power, including renewable energy, partially offset by a decrease in pricing for off system sales and hedging costs related to tolling contracts.  Volume for the three and six months ended June 30, 2011 increased primarily due to planned outages within the generation fleet.

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Deferred Energy

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Deferred energy	$	2,350	$	39,960		-94.1	%	$	9,080	$	59,423		-84.7	%

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

Amounts for the three months ended June 30, 2011 and 2010 include amortization of deferred energy of $(21) million and $7.2 million, respectively; and an over-collection of amounts recoverable in rates of $23.4 million and $32.8 million, respectively.  Amounts for the six months ended June 30, 2011 and 2010 include amortization of deferred energy of $(38.9) million and $15.3 million, respectively; and an over-collection of amounts recoverable in rates of $48 million and $44.1 million, respectively.

Other Operating Expenses

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Other operating expenses	$	61,935	$	63,292		-2.1	%	$	127,036	$	130,011		-2.3	%
Maintenance	$	19,325	$	18,219		6.1	%	$	41,662	$	35,238		18.2	%
Depreciation and amortization	$	61,913	$	57,654		7.4	%	$	119,586	$	112,755		6.1	%

Other operating expense decreased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to higher capitalization of administrative and general costs for the Harry Allen Generating Station, lower overall generation expenses, insurance premiums and employee pension and benefit expense, partially offset by an increase to bad debt expense primarily due to an adjustment in 2010 which lowered bad debt expense, higher stock compensation costs and legal and consultant fees.

Maintenance expense increased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to planned maintenance outages that occurred in 2011 at the Reid Gardner, Clark, and Navajo Generating Stations.  This increase was partially offset by a planned major outage at the Silverhawk Generating Station and maintenance at the Higgins and Lenzie Generating Stations in 2010.

Depreciation and amortization increased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to general increases in plant-in-service, including the addition of the expansion at the Harry Allen Generating Station, EWAM projects, and transmission and distribution infrastructure.

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Interest Expense

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Interest expense (net of AFUDC-debt: $2,330, $5,444, $8,120 and $9,976)	$	55,736	$	53,996		3.2	%	$	107,769	$	107,352		0.4	%

Interest expense increased for the three and six months ended June 30, 2011 compared to the same period in 2010 primarily due to increased interest expense related to the issuance of $250 million, Series X, General and Refunding Mortgage Notes in September 2010 and the issuance of $250 million, Series Y, General and Refunding Mortgage Notes in May 2011 and a decrease in AFUDC due to the completion of various construction projects, including the expansion at the Harry Allen Generating Station and EWAM projects. The increase was partially offset by the maturity of Series A General and Refunding Mortgage Notes in June 2011, partial redemptions of Series 1995 A, B, C, and D in October 2010 and lower credit facility balances in 2011.

Other Income (Expense)

	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change from Prior Year %			2011			2010			Change from Prior Year %
Interest income (expense) on regulatory items	$	(1,982	)	$	(777	)		155.1	%	$	(3,433	)	$	(808	)		324.9	%
AFUDC-equity	$	2,855		$	6,398			-55.4	%	$	9,953		$	11,760			-15.4	%
Other income	$	2,676		$	2,659			0.6	%	$	6,308		$	5,242			20.3	%
Other expense	$	(5,179	)	$	(5,172	)		0.1	%	$	(7,911	)	$	(6,304	)		25.5	%

The change in interest income (expense) on regulatory items for the three and six months ended June 30, 2011, compared to the same period in 2010, is primarily due to higher over-collected deferred energy balances in 2011.  See Note 3, Regulatory Actions, for further details of deferred energy balances.

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

Other income for the three months ended June 30, 2011 is comparable to the same period in 2010.

Other income increased for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to carrying charges for energy conservation programs, interest on the EEIR balance, and gains on investments.

Other expense for the three months ended June 30, 2011 is comparable to the same period in 2010.

Other expense increased for the six months ended June 30, 2011 compared to the same period in 2010, primarily due to the adjustment, upon final order from the PUCN in the second quarter of 2011, for EEIR revenue recorded in 2010 and increased donations, partially offset by an adjustment for excess power purchases in 2010, and losses on investments in 2010.

ANALYSIS OF CASH FLOWS

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

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

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Cash Used By Investing Activities. The decrease in cash used by investing activities was primarily due to the decrease in construction activity related to the Harry Allen Generating Station which was placed in service in May 2011.

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

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions.  Available liquidity as of June 30, 2011 was as follows (in millions):

Available Liquidity as of June 30, 2011
	NPC
Cash and Cash Equivalents	$	26.3
Balance available on Revolving Credit Facility (1)		445.6
Less reduction for hedging transactions (2)		(4.5	)
	$	467.4

(1)	As of August 3, 2011, NPC had approximately $452.6million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.
(2)	Reduction for hedging transactions reflects balances as of May 31, 2011.

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

NPC has no significant debt maturities remaining in 2011; however, NPC’s $130 million 6.50% General and Refunding Mortgage Notes, Series I, will mature on April 15, 2012.  In addition, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected in late 2012.  As of August 3, 2011, NPC has $130 million in borrowings on its revolving credit facility, not including letters of credit.

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds and the use of its revolving credit facility.  Furthermore, in order to fund long-term capital requirements and maturing debt obligations, NPC will use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE.  However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less.  In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures (discussed in the 2010 Form 10-K), re-finance debt or obtain funding through an equity or debt issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.  Additionally, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

On January 4, 2011, NPC received a capital contribution of approximately $54 million from NVE.

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

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

Financing Transactions

   5.45% General and Refunding Mortgage Notes, Series Y

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

Factors Affecting Liquidity

   Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt.  As of June 30, 2011, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725 million in long-term debt, in addition to the use of its existing credit facility.  However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting NPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of June 30, 2011, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion;
b.	Financial covenants within NPC’s financing agreements – Under its $600 million revolving credit facility, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  Based on June 30, 2011 financial statements, NPC was in compliance with this covenant and could incur up to $2.3billion of additional indebtedness;
	All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently rated investment grade.  However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and
c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $2.0 billion.

   Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of June 30, 2011, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.4 billion of additional General and Refunding Mortgage Securities as of June 30, 2011.  That amount is determined on the basis of:

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

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

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

   $600 Million Revolving Credit Facility

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

The NPC Credit Agreement contains one financial maintenance covenant that requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  In the event that NPC did not meet the financial maintenance covenant or there is an event of default, the NPC Credit Agreement would restrict dividends to NVE.  Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility.  In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

   Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under its credit facility, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.  On May 10, 2011, Moody’s upgraded NPC’s senior secured debt to Baa2.  As of June 30, 2011, the ratings are as follows:

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

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

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

   Energy Supplier Matters

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

Under these contracts, a material adverse change, which includes a credit rating downgrade, in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the 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, 2011 for all suppliers continuing to provide power under a WSPP

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agreement would approximate a $49.8 million payment or obligation to NPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.  Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.  

Gas transmission service is secured under FERC Tariffs or custom agreements.  These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved Tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.  NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of June 30, 2011, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $30.7 million.  Of this amount, approximately $23.0 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

   Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts.  As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility.  The calculation of NPC’s negative mark-to-market exposure as of May 31, 2011 was approximately $4.5 million, which amount was in effect for borrowings during the month of June 2011.  Currently, NPC only has hedging transactions with counterparties who are also lenders on the revolving credit facility; however, future transactions executed with non-lenders may require NPC to post cash collateral in the event of a credit rating downgrade.  Finally, in October 2009, NPC suspended its hedging program, and as such, expects its exposure to negative mark-to-market positions to continue to decline.

   Cross Default Provisions

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

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $3.5 million for the three months ended June 30, 2011, compared to net income of $11.3 million for the same period in 2010.  During the six months ended June 30, 2011, SPPC recognized net income of approximately $20.1 million compared to $28.4 million for the same period in 2010.

During the six months ended June 30, 2011, SPPC paid $104 million in dividends to NVE.  On August 4, 2011, SPPC declared an additional dividend to NVE of approximately $10 million.

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

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SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which SPPC calculates as operating revenues less energy costs, provides a measure of income available to support the other operating expenses of SPPC.  For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2011			2010		Change from Prior Year %			2011			2010		Change from Prior Year %
Operating Revenues:
Electric	$	164,582		$	202,877		-18.9	%	$	343,199		$	411,539		-16.6	%
Gas		36,448			40,405		-9.8	%		108,742			120,425		-9.7	%
	$	201,030		$	243,282		-17.4	%	$	451,941		$	531,964		-15.0	%
Energy Costs:
Fuel for power generation	$	42,059		$	49,595		-15.2	%	$	87,327		$	115,099		-24.1	%
Purchased power		37,900			40,581		-6.6	%		77,350			76,717		0.8	%
Gas purchased for resale		24,984			25,154		-0.7	%		77,616			90,713		-14.4	%
Deferral of energy - electric - net		(11,898	)		8,725		-236.4	%		(23,829	)		7,225		-429.8	%
Deferral of energy - gas - net		1,442			6,248		-76.9	%		4,691			5,851		-19.8	%
	$	94,487		$	130,303		-27.5	%	$	223,155		$	295,605		-24.5	%
Energy Costs by Segment:
Electric	$	68,061		$	98,901		-31.2	%	$	140,848		$	199,041		-29.2	%
Gas		26,426			31,402		-15.8	%		82,307			96,564		-14.8	%
	$	94,487		$	130,303		-27.5	%	$	223,155		$	295,605		-24.5	%
Gross Margin by Segment:
Electric	$	96,521		$	103,976		-7.2	%	$	202,351		$	212,498		-4.8	%
Gas		10,022			9,003		11.3	%		26,435			23,861		10.8	%
	$	106,543		$	112,979		-5.7	%	$	228,786		$	236,359		-3.2	%

Electric gross margin decreased for the three months ended June 30, 2011, compared to the same period in 2010, primarily due to the sale of the California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements, partially offset by the related five year purchased power agreement entered into as a condition to the sale of the assets.  Further contributing to this decrease in gross margin was decreased usage among residential and commercial classes due to milder weather.

Electric gross margin decreased for the six months ended June 30, 2011, compared to the same period in 2010, primarily due to the sale of the California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements, partially offset by the related five year purchased power agreement entered into as a condition to the sale of the assets.  Partially offsetting this decrease in gross margin was slight increased growth in all customer classes.

Gas gross margin increased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to increased usage among residential and commercial classes as a result of colder weather.

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

Electric Operating Revenue

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Operating Revenues:
Residential	$	50,997	$	69,960		-27.1	%	$	115,046	$	152,635		-24.6	%
Commercial		62,476		81,076		-22.9	%		124,561		157,499		-20.9	%
Industrial		35,141		44,529		-21.1	%		69,633		86,882		-19.9	%
Retail  Revenues		148,614		195,565		-24.0	%		309,240		397,016		-22.1	%
Other		15,968		7,312		118.4	%		33,959		14,523		133.8	%
Total Operating Revenues	$	164,582	$	202,877		-18.9	%	$	343,199	$	411,539		-16.6	%
Retail sales in thousands of MWhs		1,796		1,923		-6.6	%		3,649		3,883		-6.0	%
Average retail revenue per MWh	$	82.75	$	101.70		-18.6	%	$	84.75	$	102.24		-17.1	%

SPPC’s retail revenues decreased for the three and six months ended June 30, 2011 compared to the same periods in 2010, due to decreases in retail rates as a result of SPPC’s annual deferred energy case effective October 1, 2010, and various BTER quarterly updates.  (See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2010 Form 10-K).  Retail revenues also decreased due to the sale of the California assets on January 1, 2011 (see Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements). These decreases were offset by a slight increase in rates due to SPPC’s 2010 GRC effective January 1, 2011.  For the three months ended June 30, 2011, excluding California customers, the average number of retail and commercial customers increased by 0.3% and 0.6%, respectively, while industrial customers decreased by 4.8%.  For the six months ended June 30, 2011, excluding California customers, the average number of retail and commercial customers increased 0.3% and 1.1%, respectively, while industrial customers remain unchanged.

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

Gas Operating Revenues

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Gas Operating Revenues:
Residential	$	18,074	$	20,382		-11.3	%	$	57,252	$	62,745		-8.8	%
Commercial		7,270		8,916		-18.5	%		24,546		29,397		-16.5	%
Industrial		2,584		3,505		-26.3	%		7,370		9,444		-22.0	%
Retail  Revenues		27,928		32,803		-14.9	%		89,168		101,586		-12.2	%
Wholesale Revenues		7,737		7,007		10.4	%		17,915		17,569		2.0	%
Miscellaneous		783		595		31.6	%		1,659		1,270		30.6	%
Total Gas Revenues	$	36,448	$	40,405		-9.8	%	$	108,742	$	120,425		-9.7	%
Retail sales in thousands of Dths		2,871		2,852		0.7	%		9,405		8,836		6.4	%
Average retail revenue per Dth	$	9.73	$	11.50		-15.4	%	$	9.48	$	11.50		-17.5	%

SPPC’s retail gas revenues decreased for the three and nine months ended June 30, 2011, compared to the same periods in 2010, primarily due to decreased retail rates as a result of SPPC’s various BTER quarterly updates and 2010 Natural Gas and Propane

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Deferred Rate Case effective October 1, 2010. (See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2010 Form 10-K). These decreases were partially offset by increased customer usage resulting from colder 2011 temperatures and a slight BTGR increase as a result of SPPC’s 2010 GRC effective January 1, 2011. For the three months ended June 30, 2011 the average number of residential and commercial customers increased 1.0% and 0.8%, respectively, while industrial customers decreased 7.6%.  For the six months ended June 30, 2011 the average number of residential and commercial customers increased 0.7% and 0.7%, respectively, while the industrial customers decreased 4.1%.

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

Energy Costs

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

• Weather

• Plant outages

• Total system demand

• Resource constraints

• Transmission constraints

• Gas transportation constraints

• Natural gas constraints

• Long-term contracts

• Mandated power purchases

• Generation efficiency; and

• Volatility of commodity prices

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Energy Costs
Fuel for power generation	$	42,059	$	49,595		-15.2	%	$	87,327	$	115,099		-24.1	%
Purchased power		37,900		40,581		-6.6	%		77,350		76,717		0.8	%
Total Energy Costs	$	79,959	$	90,176		-11.3	%	$	164,677	$	191,816		-14.1	%
MWhs
MWhs Generated (in thousands)		977		1,110		-12.0	%		2,026		2,300		-11.9	%
Purchased Power (in thousands)		1,104		1,007		9.6	%		2,203		1,876		17.4	%
Total MWhs		2,081		2,117		-1.7	%		4,229		4,176		1.3	%
Average cost per MWh
Average fuel cost per MWh of Generated Power	$	43.05	$	44.68		-3.7	%	$	43.10	$	50.04		-13.9	%
Average cost per MWh of Purchased Power	$	34.33	$	40.30		-14.8	%	$	35.11	$	40.89		-14.1	%
Average total cost per MWh	$	38.42	$	42.60		-9.8	%	$	38.94	$	45.93		-15.2	%

Energy costs and the average cost per MWh decreased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to a decrease in costs associated with hedging activities and a decrease in natural gas prices. Total system demand remained relatively stable for the three and six months ended June 30, 2011 compared to the same period in 2010.

• Fuel for power generation costs and average cost per MWh decreased for the three and six months ending June 30, 2011 compared to the same period in 2010, primarily due to a decrease in hedging activities and  a decrease in natural gas costs.  Fuel for generation volume decreased due to planned outages at the Valmy Generating Station.

• Purchased power costs and average cost per MWh decreased for the three months ending June 30, 2011 compared to the same period in 2010, primarily due to a decrease in the cost of purchased power, including renewable energy.  For the six months ended June 30, 2011, purchased power costs increased primarily due to an increase in volume.  The increase was partially offset by a decrease in the cost of renewable energy.  The average cost per MWh of purchased power decreased primarily due a decrease in the cost of purchased power, including renewable energy.  Volume increased for both the three and six months ended June 30, 2011 due to planned system outages discussed above.

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Gas Purchased for Resale

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Gas purchased for resale	$	24,984	$	25,154		-0.7	%	$	77,616	$	90,713		-14.4	%
Gas purchased for resale (in thousands of Dths)		4,688		4,596		2.0	%		14,759		12,141		21.6	%
Average cost per Dth	$	5.33	$	5.47		-2.6	%	$	5.26	$	7.47		-29.6	%

Gas purchased for resale and average cost per Dth decreased for the three and six months ended June 30, 2011, as compared to the same periods in 2010.  The decrease is primarily due to decreased hedging and natural gas costs.  Volume increased primarily due to colder weather in the first quarter and an increase in the purchase of gas in an effort to optimize pipeline capacity.

Deferred Energy

	Three Months Ended June 30,								Six Months Ended June 30,
	2011			2010		Change from Prior Year %			2011			2010		Change from Prior Year %
Deferral of energy - electric - net	$	(11,898	)	$	8,725		-236.4	%	$	(23,829	)	$	7,225		-429.8	%
Deferral of energy - gas - net		1,442			6,248		-76.9	%		4,691			5,851		-19.8	%
	$	(10,456	)	$	14,973				$	(19,138	)	$	13,076

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

Deferred energy – electric for the three months ended June 30, 2011 and 2010 reflect amortization of deferred energy costs of ($23.3) million and ($5.4) million, respectively; and an over-collection of amounts recoverable in rates of $11.4 million and $14.1 million, respectively.  For the six months ended June 30, 2011 and 2010, amortization of deferred energy was ($48.3) million and ($11.2) million, respectively; with an over-collection of amounts recoverable in rates of $24.5 million and $18.4 million, respectively.

Deferred energy – gas for the three months ended June 30, 2011 and 2010 reflect amortization of deferred energy of ($3.3) million, and ($1.6) million, respectively; and an over-collection of amounts recoverable in rates of $4.7 million and $7.9 million, respectively.  For the six months ended June 30, 2011 and 2010, amortization of deferred energy was ($10.7) million and ($5.1) million, respectively; with an over-collection of amounts recoverable in rates of $15.3 million and $11.0 million, respectively.

Other Operating Expenses

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Other operating expenses	$	34,687	$	37,014		-6.3	%	$	74,903	$	76,367		-1.9	%
Maintenance	$	12,861	$	10,641		20.9	%	$	20,286	$	19,351		4.8	%
Depreciation and amortization	$	27,693	$	27,042		2.4	%	$	53,122	$	52,889		0.4	%

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Other operating expense decreased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to lower employee pension and benefit expenses, 2010 costs related to the involuntary severance program, and lower outside consulting fees and lease expense; partially offset by regulatory amortizations and stock compensation costs.

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

Depreciation and amortization increased for the three and six months ended June 30, 2011, compared to the same period in 2010, primarily due to regular system growth in plant-in-service.

Interest Expense

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change from Prior Year %			2011		2010		Change from Prior Year %
Interest expense (net of AFUDC-debt: $505, $482, $925 and $888)	$	16,774	$	17,113		-2.0	%	$	33,720	$	34,158		-1.3	%

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

Other Income (Expense)

	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change from Prior Year %			2011			2010			Change from Prior Year %
Interest income (expense) on regulatory items	$	(2,080	)	$	(2,220	)		-6.3	%	$	(4,391	)	$	(4,260	)		3.1	%
AFUDC-equity	$	667		$	740			-9.9	%	$	1,211		$	1,331			-9.0	%
Other income	$	1,177		$	10,142			-88.4	%	$	3,229		$	11,897			-72.9	%
Other expense	$	(3,554	)	$	(4,401	)		-19.2	%	$	(5,148	)	$	(6,270	)		-17.9	%

The change in interest income (expense) on regulatory items for the three months ended June 30, 2011, compared to the same period in 2010, is due to lower over-collected deferred energy balances in 2011.

The change in interest income (expense) on regulatory items for the six months ended June 30, 2011, compared to the same period in 2010, is due to higher over-collected deferred energy balances in 2011.

AFUDC-equity decreased for the three and six months ended June 30, 2011 compared to the same period in 2010, primarily due to a decrease in construction.

The decrease in other income for the three and six months ended June 30, 2011, compared to the same period in 2010, is primarily due to the gain on sale of Independence Lake in 2010, as further discussed in Note 10, Assets Held for Sale, of the Notes to Financial Statements in the 2010 Form 10-K, and a decrease in income from sub-leases.

Other expense decreased for the three and six months ended June 30, 2011, compared to the same periods in 2010, primarily due to a decrease in lease costs and donations partially offset by an adjustment, upon final order from the PUCN in the second quarter of 2011, for EEIR revenue recorded in 2010.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows increased during the six months ended June 30, 2011, compared to the same period in 2010, due to an increase in cash from investing activities, offset partially by a reduction in cash from operating activities and an increase in cash used by financing activities.

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

Cash From Investing Activities. Cash from investing activities increased due to the receipt of proceeds from the sale of California assets, as discussed in Note 10, Assets Held for Sale, of the Condensed Notes to Financial Statements.  Also contributing to the change in cash from investing activities was the decrease in general construction for infrastructure.

Cash Used By Financing Activities. The increase in cash used by financing activities is primarily due to dividends to NVE.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of June 30, 2011 was as follows (in millions):

Available Liquidity as of June 30, 2011
	SPPC
Cash and Cash Equivalents	$	76.1
Balance available on Revolving Credit Facility (1)		237.5
Less Reduction for Hedging Transactions (2)		(0.9	)
	$	312.7

(1)	As of August 3, 2011, SPPC had approximately $236.7 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.
(2)	Reduction for hedging transactions reflects balance as of May 31, 2011.

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

SPPC has no significant debt maturities in either 2011 or 2012.  As of August 3, 2011, SPPC has no borrowings on its revolving credit facility, not including letters of credit.

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds and the use of its revolving credit facility.  Furthermore, in order to fund long-term capital requirements and maturing debt obligations, SPPC will use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE.  However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less.  In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures (discussed in the 2010 Form 10-K), refinance debt or obtain funding through an equity or debt issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.  Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the six months ended June 30, 2011, SPPC paid dividends to NVE of $104 million.

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

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

Factors Affecting Liquidity

   Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt.  As of June 30, 2011, the most restrictive of the factors below is the PUCN authority.  Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million.  However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting SPPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of June 30, 2011, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million;
b.	Financial covenants within SPPC’s financing agreements – Under SPPC’s $250 million revolving credit facility, the Utility must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  Based on June 30, 2011 financial statements, SPPC was in compliance with this covenant and could incur up to $817 million of additional indebtedness;
	All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently rated investment grade.  However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants; and
c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $2.0billion.

   Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of June 30, 2011, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $728 millionof additional General and Refunding Mortgage Securities as of June 30, 2011.  That amount is determined on the basis of:

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

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

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

   $250 Million Revolving Credit Facility

SPPC’s $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates.  The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation.  The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such

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reduction, the SPPC Credit Agreement provides that reduction in the availability under the revolving credit facility to SPPC shall not exceed 50% of the total commitments then in effect under the revolving credit facility.

The SPPC Credit Agreement contains one financial maintenance covenant that requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  In the event that SPPC did not meet the financial maintenance covenant or there is an event of default, the SPPC Credit Agreement would restrict dividends to NVE.  Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility.  In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

   Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under its credit facility, the potential exposure of SPPC to collateral calls under various contracts, and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  On May 10, 2011, Moody’s upgraded SPPC’s senior secured debt to Baa2.  As of June 30, 2011, the ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB*	Baa2*	BBB*

*Investment grade

(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

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

   Energy Supplier Matters

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

Under these contracts, a material adverse change, which includes a credit rating downgrade, in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event, giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single 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, 2011 for all suppliers continuing to provide power under a WSPP agreement, no amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.  Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.  Most contracts and confirmations for natural gas

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purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery.  At the present time, no counterparties require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved Tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.

   Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts.  As discussed under SPPC’s Financing Transactions, the availability under SPPC’s revolving credit facility is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility.  The calculation of SPPC’s negative mark-to-market exposure as of May 30, 2011 was approximately $0.9 million, which amount was in effect for borrowings during the month of June 2011.  Currently, SPPC only has hedging transactions with counterparties who are also lenders on the revolving credit facility; however, future transactions executed with non-lenders may require SPPC to post cash collateral in the event of a credit rating downgrade.  Finally, in October 2009, SPPC suspended its hedging program, and as such, expects its exposure to negative mark-to-market positions to continue to decline.

   Cross Default Provisions

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

RECENT PRONOUNCEMENTS

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

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ITEM 3A.                       QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2011, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity.  Such instruments are fixed and variable rate debt.  Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands):

		2011
		Expected Maturities
									Fair
		2011	2012	2013	2014	2015	Thereafter	Total	Value
Long-Term Debt
	NVE
	Fixed Rate	$             -	$             -	$             -	$              -	$             -	$     506,500	$     506,500	$526,868
	Average Interest Rate	-	-	-	-	-	6.44%	6.44%
	NPC
	Fixed Rate	$             -	$  130,000	$             -	$  125,000	$   250,000	$  2,755,000	$  3,260,000	$3,690,602
	Average Interest Rate	-	6.50%	-	7.38%	5.88%	6.43%	6.42%
	Variable Rate	$             -	$             -	$  140,000	$              -	$              -	$     173,775	$     313,775	$   313,775
	Average Interest Rate	-	-	2.45%	-	-	0 .67%	1.47%
	SPPC
	Fixed Rate	$             -	$             -	$  250,000	$             -	$              -	$     701,742	$    951,742	$ 1,077,982
	Average Interest Rate	-	-	5.45%	-	-	6.27%	6.05%
	Variable Rate	$             -	$             -	$             -	$              -	$              -	$     214,675	$     214,675	$    214,675
	Average Interest Rate	-	-	-	-	-	0.65%	0.65%	-
	TOTAL DEBT	$             -	$  130,000	$  390,000	$  125,000	$  250,000	$  4,351,692	$  5,246,692	$ 5,823,902

Commodity Price Risk

See the 2010 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk.  No material changes in commodity risk have occurred since December 31, 2010.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties.  Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition.  The Utilities’ credit risk associated with trading counterparties was approximately $51.4 million as of June 30, 2011, which compares to balances of $48.9 million at March 31, 2011. The increase from March 31, 2011 is primarily due to the decrease in prices of natural gas and power during the first quarter of 2011.

ITEM 4.                      CONTROLS AND PROCEDURES

(a)   Evaluation of disclosure controls and procedures.

NVE’s, NPC’s and SPPC’s principal executive officer and principal financial officer, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934), have concluded that, as of June 30, 2011, the registrants’ disclosure controls and procedures were effective.

(b)   Change in internal controls over financial reporting.

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

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PART II

ITEM 1.                      LEGAL PROCEEDINGS

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had, or in the opinion of management, is expected to have a significant impact on their financial positions or results of operations.  See Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements for further discussion of other legal matters.

ITEM 1A.                      RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC).  The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2010 Form 10-K.  The risks and uncertainties described below are not the only ones we face.  Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

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

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

None.

ITEM 3.                      DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 5.                      OTHER INFORMATION

In the proxy statement that NVE provided to its stockholders in connection with its 2011 Annual Meeting of Stockholders held on May 3, 2011 (the “Annual Meeting”), NVE’s BOD recommended that the stockholders vote, on an advisory basis, in favor of an annual frequency for future non-binding advisory votes on executive compensation.  As reported in NVE’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2011, at the Annual Meeting, NVE’s stockholders cast the highest number of votes in favor of an annual frequency for future non-binding advisory votes on executive compensation.

Based on these results and consistent with the previous recommendation of NVE’s BOD, the BOD determined at its meeting on August 4, 2011 that NVE will hold non-binding advisory votes on executive compensation on an annual basis until the next vote on the frequency of stockholder votes on executive compensation, which will be no later than NVE’s annual meeting of stockholders in 2017.

At a meeting held on August 4, 2011, the BOD of NVE approved an equity grant of 110,000 shares to Michael W. Yackira, President and Chief Executive Officer of NVE.  The equity grant to Mr. Yackira is in the form of restricted stock units, which shall vest four years from the effective date of the equity grant subject to Mr. Yackira's continued employment with NVE.  The effective date of the equity grant to Mr. Yackira is August 4, 2011.

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ITEM 6.                      EXHIBITS

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

(10)    NV Energy, Inc.:

10.1 Amended and Restated Articles of Incorporation of NV Energy, Inc. effective May 9, 2011.

• Amended  and Restated NV Energy, Inc. 2004 Executive Long-Term Incentive Plan (as of January 1, 2011) filed as Exhibit 99.3 to Post-Effective Amendment No. 3 to Registration Statement on Form S-8 (File No. 333-146822).

(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.

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

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

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

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SIGNATURES

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

	NV Energy, Inc.
	(Registrant)
Date: August 5, 2011	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date: August 5, 2011	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Nevada Power Company d/b/a NV Energy
	(Registrant)
Date: August 5, 2011	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date: August 5, 2011	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)
Date: August 5, 2011	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date: August 5, 2011	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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