UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1 to Form 10-K)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF

 THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

		I.R.S. Employer
Commission File Number	Registrant, Address of Principal Executive Offices and Telephone Number	Identification Number	State of 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 NV ENERGY	88-0420104	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000
0-00508	SIERRA PACIFIC POWER COMPANY d/b/a NV ENERGY	88-0044418	Nevada
	P.O. Box 10100 (6100 Neil Road)
	Reno, Nevada 89520-0024 (89511)
	(775) 834-4011

(Title of each class)	(Name of exchange on which registered)
Securities registered pursuant to Section 12(b) of the Act:
Securities of NV Energy, Inc.:
Common Stock, $1.00 par value	New York Stock Exchange
7.803% Senior Notes Due 2012	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Securities of Nevada Power Company:
Common Stock, $1.00 stated value
Securities of Sierra Pacific Power Company:
Common Stock, $3.75 par value

 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

NV Energy, Inc.  Yesþ Noo  Nevada Power Company Yeso Noþ  Sierra Pacific Power Company Yeso  Noþ

     Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso   Noþ

     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  o   No  o  (Response applicable to all registrants).

     Indicate by check mark whether each of the registrants (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

     Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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

NV Energy, Inc.:  Large accelerated filer þ  Accelerated filer o  Non-accelerated filer  o   Smaller reporting company o

Nevada Power Company:  Large accelerated filer  o  Accelerated filer  o  Non-accelerated filer þ   Smaller reporting company o

Sierra Pacific Power Company: Large accelerated filer o  Accelerated filer o Non-accelerated filer þ  Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso  Noþ (Response applicable to all registrants)

State the aggregate market value of NV Energy, Inc.'s common stock held by non-affiliates. As of June 30, 2009: $ 2,531,506,363

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

Common Stock, $1.00 par value, of NV Energy, Inc. outstanding at February 19, 2010:   234,843,222 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 par value, of Sierra Pacific Power Company.

DOCUMENTS INCORPORATED BY REFERENCE:

     Portions of NV Energy, Inc.'s definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 4, 2010, are incorporated by reference into Part III hereof.

     This combined Annual Report on Form 10-K 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.

EXPLANATORY NOTE

NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company (the “Companies”) are filing this 10-K/A to our combined Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (“Form 10-K”) for the sole purpose of adding the conformed signature of Deloitte & Touche LLP to (A) the “Report of Independent Registered Public Accounting Firm” for each of  NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company in Item 8; (B) the “Report of Independent Registered Public Accounting Firm" for  NV Energy, Inc. in Item 9A(T); and (C) the “Consent of Independent Accounting Firm” for each of NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company in Item 15, filed respectively as Exhibit 23.1, Exhibit 23.2 and Exhibit 23.3 to the Form 10-K, each of which  were inadvertently omitted within our Form 10-K.  At the time of the February 22, 2010 filing of the Form 10-K with the Securities and Exchange Commission (the "SEC"), the Companies were in possession of the audit opinions and consents, but the signature in typed form was inadvertently omitted from the electronic version filed with the SEC.   For convenience and ease of reference, this amendment sets forth “Item 8- Financial Statements and Supplementary Data” and "Item 9A(T)- Controls and Procedures" from the Form 10-K in their entirety with the applicable changes.  Because this amendment only incorporates the signature in typed form of Deloitte & Touche LLP on the “Reports of Independent Registered Public Accounting Firm” and the “Consents of Independent Accounting Firm”, the date of such reports and consents remain as originally filed.

 This Form 10-K/A continues to speak as of the date of the Form 10-K and no attempt has been made in this Form 10-K/A to modify or update disclosures in the original Form 10-K except as noted above. This Form 10-K/A does not reflect events occurring after the filing of the Form 10-K or modify or update any related disclosures and any information not affected by the amendments contained in this Form 10-K/A is unchanged and reflects the disclosure made at the time of the filing of the Form 10-K with the SEC. In particular, any forward-looking statements included in this Form 10-K/A represent management’s view as of the filing date of the Form 10-K. Accordingly, this Form 10-K/A should be read in conjunction with any documents incorporated by reference in the Form 10-K and our filings made with the SEC subsequent to the filing of the Form 10-K, including any amendments to those filings.

ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
			Page
Reports of Independent Registered Public Accounting Firm			84
NV Energy, Inc.:
	Consolidated Income Statements for the Years Ended December 31, 2009, 2008 and 2007		87
	Consolidated Balance Sheets as of December 31, 2009 and 2008		88
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		90
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		91
	Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007		92
Nevada Power Company:
	Consolidated Income Statements for the Years Ended December 31, 2009, 2008 and 2007		93
	Consolidated Balance Sheets as of December 31, 2009 and 2008		94
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		96
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		97
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2009, 2008 and 2007		98
Sierra Pacific Power Company:
	Consolidated Income Statements for the Years Ended December 31, 2009, 2008 and 2007		99
	Consolidated Balance Sheets as of December 31, 2009 and 2008		100
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		102
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		103
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2009, 2008 and 2007		104
Notes to Financial Statements for NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company			105

83

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

NV Energy, Inc.

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets of NV Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income (loss), common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NV Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 22, 2010

84

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income (loss), common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Nevada Power Company and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 22, 2010

85

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income (loss), common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Power Company and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 22, 2010

86

NV ENERGY, INC.
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
	Year Ended December 31,
	2009			2008			2007
OPERATING REVENUES	$	3,585,798		$	3,528,113		$	3,600,960
OPERATING EXPENSES:
Fuel for power generation		881,768			1,039,267			837,355
Purchased power		758,736			974,343			1,036,905
Gas purchased for resale		153,607			170,468			150,879
Deferred energy		289,076			(10,265	)		321,973
Other operating expenses		453,413			394,019			379,446
Maintenance		102,309			94,069			99,035
Depreciation and amortization		321,921			260,608			235,532
Taxes other than income		60,885			53,525			50,113
Total Operating Expenses		3,021,715			2,976,034			3,111,238
OPERATING INCOME		564,083			552,079			489,722
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt:         2009-$20,229; 2008-$29,527; 2007-$25,967)		(334,314	)		(300,857	)		(279,788	)
Interest income (expense) on regulatory items		(2,280	)		5,255			26,154
AFUDC-equity		24,274			38,441			31,809
Carrying charge for Lenzie		-			-			16,080
Gain on sale of investment		-			-			1,369
Other income		33,122			34,278			24,580
Other expense		(26,498	)		(24,955	)		(25,076	)
Total Other Income (Expense)		(305,696	)		(247,838	)		(204,872	)
Income Before Income Tax Expense		258,387			304,241			284,850
Income tax expense (Note 10)		75,451			95,354			87,555
NET INCOME	$	182,936		$	208,887		$	197,295
Amount per share basic and diluted (Note 15)
Net Income per share basic and diluted	$	0.78		$	0.89		$	0.89
Weighted Average Shares of Common Stock Outstanding - basic		234,542,292			234,031,750			222,180,440
Weighted Average Shares of Common Stock Outstanding - diluted		235,180,688			234,585,004			222,554,024
Dividends Declared Per Share of Common Stock	$	0.41		$	0.34		$	0.16
The accompanying notes are an integral part of the financial statements.

87

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
		December 31,
		2009		2008
ASSETS
Current Assets:
Cash and cash equivalents		$	62,706	$	54,359
Accounts receivable less allowance for uncollectible accounts:
	2009 - $32,341, 2008 - $32,884		400,911		410,184
Deferred energy (Note 3)			-		50,436
Materials, supplies and fuel, at average cost			124,040		124,271
Risk management assets (Note 9)			27,558		16,118
Current income taxes receivable			-		5,487
Deferred income taxes (Note 10)			87,562		49,996
Other current assets			44,298		52,633
Total Current Assets			747,075		763,484
Utility Property:
Plant in service			10,833,622		10,175,741
Construction work-in-progress			716,128		605,163
Total			11,549,750		10,780,904
Less accumulated provision for depreciation			2,884,199		2,603,287
Total Utility Property, Net			8,665,551		8,177,617
Investments and other property, net (Note 4)			51,169		25,181
Deferred Charges and Other Assets:
Deferred energy (Note 3)			138,963		231,027
Regulatory assets (Note 3)			1,218,778		1,415,286
Regulatory asset for pension plans (Note 3)			264,892		413,544
Risk management assets (Note 9)			6,732		9,959
Other deferred charges and assets			173,145		169,266
Total Deferred Charges and Other Assets			1,802,510		2,239,082
Assets Held for Sale (Note 16)			147,158		142,506
TOTAL ASSETS		$	11,413,463	$	11,347,870
(Continued)

88

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
	December 31,
	2009			2008
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt (Note 6)	$	134,474		$	9,291
Accounts payable		352,000			400,084
Accrued expenses		134,328			131,720
Risk management liabilities (Note 9)		66,871			313,846
Deferred energy (Note 3)		191,405			28,546
Other current liabilities		67,301			87,060
Total Current Liabilities		946,379			970,547
Long-term debt (Note 6)		5,303,357			5,266,982
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes (Note 10)		1,072,780			920,481
Deferred investment tax credit		22,541			25,923
Accrued retirement benefits		149,925			288,841
Risk management liabilities (Note 9)		2,233			53,403
Regulatory liabilities (Note 3)		386,019			350,526
Other deferred credits and liabilities		280,560			315,881
Total Deferred Credits and Other Liabilities		1,914,058			1,955,055
Liabilities Held for Sale (Note 16)		25,747			24,100
Shareholders' Equity:
Common stock		234,834			234,317
Other paid-in capital		2,700,329			2,694,792
Retained earnings		295,247			208,437
Accumulated other comprehensive loss		(6,488	)		(6,360	)
Total Shareholders' Equity		3,223,922			3,131,186
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	11,413,463		$	11,347,870
The accompanying notes are an integral part of the financial statements.
(Concluded)

89

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
	For the Year Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	182,936		$	208,887		$	197,295
Adjustments to reconcile net income to net cash from operating          activities:
Depreciation and amortization		321,921			260,608			235,532
Deferred taxes and deferred investment tax credit		111,219			52,060			79,337
AFUDC-equity		(24,274	)		(38,441	)		(31,809	)
Deferred energy		306,406			2,717			309,587
Carrying charge on Lenzie Generating Station		-			-			(16,080	)
Reinstated interest on deferred energy		-			-			(11,076	)
Gain on sale of investment		-			-			(1,369	)
Other, net		(2,004	)		100,482			71,543
Changes in certain assets and liabilities:
Accounts receivable		12,733			39,776			(19,276	)
Materials, supplies and fuel		465			(7,908	)		(13,725	)
Other current assets		8,335			(6,724	)		1,639
Accounts payable		(31,888	)		(12,028	)		42,958
Accrued retirement benefits		(20,080	)		(79,242	)		(75,820	)
Other current liabilities		(17,287	)		40,747			22,475
Risk management assets and liabilities (Note 9)		5,058			(4,924	)		10,088
Other deferred assets		(13,831	)		(51,874	)		498
Other regulatory assets		(69,937	)		(67,460	)		(45,864	)
Other deferred liabilities		(18,251	)		22,238			(2,112	)
Net Cash from Operating Activities		751,521			458,914			753,821
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(843,132	)		(1,535,503	)		(1,165,517	)
Customer advances for construction		(8,369	)		(11,981	)		8,230
Contributions in aid of construction		76,940			62,521			32,165
Proceeds from sale of investment		-			-			1,935
Investments and other property - net		(26,061	)		4,301			2,810
Net Cash used by Investing Activities		(800,622	)		(1,480,662	)		(1,120,377	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,418,872			2,135,151			1,246,383
Retirement of long-term debt		(1,271,350	)		(1,114,226	)		(1,044,866	)
Sale of Common Stock		6,051			5,756			213,339
Proceeds from exercise of stock options		-			-			548
Dividends paid		(96,125	)		(79,714	)		(35,417	)
Net Cash from Financing Activities		57,448			946,967			379,987
Net Increase (Decrease) in Cash and Cash Equivalents		8,347			(74,781	)		13,431
Beginning Balance in Cash and Cash Equivalents		54,359			129,140			115,709
Ending Balance in Cash and Cash Equivalents	$	62,706		$	54,359		$	129,140
Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during period for:
Interest	$	325,508		$	284,044		$	267,082
Income taxes	$	(13,186	)	$	10,677		$	9,727
Significant non-cash transactions:
Accrued construction expenses as of December 31,	$	127,786		$	143,982		$	111,163
The accompanying notes are an integral part of the financial statements.

90

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
	Year Ended December 31,
	2009			2008			2007
NET INCOME	$	182,936		$	208,887		$	197,295
OTHER COMPREHENSIVE INCOME (LOSS)
Change in compensation retirement benefits liability and amortization (Net of taxes $72, $284 and $1,250 in 2009, 2008 and 2007, respectively)
	$	(128	)	$	(492	)	$	(2,323	)
OTHER COMPREHENSIVE LOSS	$	(128	)	$	(492	)	$	(2,323	)
COMPREHENSIVE INCOME	$	182,808		$	208,395		$	194,972
The accompanying notes are an integral part of the financial statements.

91

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)
	December 31,
	2009			2008			2007
Common Stock:
Balance at Beginning of Year	$	234,317		$	233,739		$	221,030
Stock issuance/exchange, CSIP, DRP, ESPP and other		517			578			12,709
Balance at end of year		234,834			234,317			233,739
Other Paid-In Capital:
Balance at Beginning of Year		2,694,792			2,684,845			2,483,244
Premium on issuance/exchange of common stock		-			-			190,808
Common Stock issuance costs		-			(90	)		(298	)
Stock purchase and dividend reinvestment		2,494			2,141			504
Tax Benefit from stock option exercises		7			365			891
CSIP, DRP, ESPP and other		3,036			7,531			9,696
Balance at End of Year		2,700,329			2,694,792			2,684,845
Retained Earnings:
Balance at Beginning of Year		208,437			83,859			(78,432	)
Adjustments to beginning balances: Compensation retirement benefits in 2008     (net of taxes of ($2,514)), and uncertain tax positions in 2007		(1	)		(4,669	)		487
Income for the year		182,936			208,887			197,295
Common stock dividends declared		(96,125	)		(79,640	)		(35,491	)
Balance at End of Year		295,247			208,437			83,859
Accumulated Other Comprehensive Income (Loss):
Balance at Beginning of Year		(6,360	)		(5,868	)		(3,545	)
Change in compensation retirement benefits liability and amortization      (net of taxes of $72, $284 and $1,250 in 2009, 2008 and 2007 respectively)		(128	)		(492	)		(2,323	)
Balance at End of Year		(6,488	)		(6,360	)		(5,868	)
Total Common Shareholders' Equity at End of Year	$	3,223,922		$	3,131,186		$	2,996,575
The accompanying notes are an integral part of the financial statements.

92

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
	Year Ended December 31,
	2009			2008			2007
OPERATING REVENUES	$	2,423,377		$	2,315,427		$	2,356,620
OPERATING EXPENSES:
Fuel for power generation		587,647			755,925			594,382
Purchased power		627,759			680,816			688,606
Deferred energy		207,611			(6,947	)		233,166
Other operating expenses		279,865			249,236			232,610
Maintenance		71,019			63,282			67,482
Depreciation and amortization		215,873			171,080			152,139
Taxes other than income		37,241			32,069			29,823
Total Operating Expenses		2,027,015			1,945,461			1,998,208
OPERATING INCOME		396,362			369,966			358,412
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt:            2009 - $17,184; 2008 - $20,063; 2007 - $13,196)		(226,252	)		(186,822	)		(174,667	)
Interest income on regulatory items		3,463			7,342			25,289
AFUDC-Equity		21,025			25,917			15,861
Carrying charge for Lenzie		-			-			16,080
Other income		19,658			16,631			14,423
Other expense		(18,320	)		(10,221	)		(11,352	)
Total Other Income (Expense)		(200,426	)		(147,153	)		(114,366	)
Income Before Income Tax Expense		195,936			222,813			244,046
Income tax expense (Note 10)		61,652			71,382			78,352
NET INCOME	$	134,284		$	151,431		$	165,694
The accompanying notes are an integral part of the financial statements.

93

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
		December 31,
		2009		2008
ASSETS
Current Assets:
Cash and cash equivalents		$	42,609	$	28,594
Accounts receivable less allowance for uncollectible accounts:
	2009 - $29,375, 2008 - $30,621		254,027		238,379
Deferred energy (Note 3)			-		50,436
Materials, supplies and fuel, at average cost			69,176		74,103
Risk management assets (Note 9)			21,902		11,724
Intercompany income taxes receivable			10,356		20,695
Deferred income taxes (Note 10)			58,425		2,682
Other current assets			27,855		34,657
Total Current Assets			484,350		461,270
Utility Property:
Plant in service			7,414,432		6,884,033
Construction work-in-progress			627,026		514,096
Total			8,041,458		7,398,129
Less accumulated provision for depreciation			1,727,710		1,500,502
Total Utility Property, Net			6,313,748		5,897,627
Investments and other property, net (Note 4)			41,167		19,701
Deferred Charges and Other Assets:
Deferred energy (Note 3)			138,963		231,027
Regulatory assets (Note 3)			856,769		971,354
Regulatory asset for pension plans (Note 3)			129,709		187,894
Risk management assets (Note 9)			5,590		7,346
Other deferred charges and assets			126,075		127,928
Total Deferred Charges and Other Assets			1,257,106		1,525,549
TOTAL ASSETS		$	8,096,371	$	7,904,147
(Continued)

94

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
	December 31,
	2009			2008
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt (Note 6)	$	119,474		$	8,691
Accounts payable		249,962			262,552
Accounts payable, affiliated companies		32,414			32,901
Accrued expenses		86,983			80,069
Risk management liabilities (Note 9)		39,122			222,856
Deferred energy (Note 3)		74,129			-
Other current liabilities		52,306			72,762
Total Current Liabilities		654,390			679,831
Long-term debt (Note 6)		3,535,440			3,385,106
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes (Note 10)		794,890			635,523
Deferred investment tax credit		8,698			10,001
Accrued retirement benefits		39,678			103,023
Risk management liabilities (Note 9)		1,165			35,241
Regulatory liabilities (Note 3)		210,287			188,709
Other deferred credits and liabilities		201,784			239,146
Total Deferred Credits and Other Liabilities		1,256,502			1,211,643
Shareholder's Equity:
Common stock		1			1
Other paid-in capital		2,254,189			2,254,182
Retained earnings		399,345			377,055
Accumulated other comprehensive loss		(3,496	)		(3,671	)
Total Shareholder's Equity		2,650,039			2,627,567
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	8,096,371		$	7,904,147
The accompanying notes are an integral part of the financial statements.
(Concluded)

95

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
	For the Year Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	134,284		$	151,431		$	165,694
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		215,873			171,080			152,139
Deferred taxes and deferred investment tax credit		96,831			45,039			56,868
AFUDC-equity		(21,025	)		(25,917	)		(15,861	)
Deferred energy		216,629			4,211			218,992
Carrying charge on Lenzie Generating Station		-			-			(16,080	)
Reinstated interest on deferred energy		-			-			(11,076	)
Other, net		(34,291	)		73,209			38,821
Changes in certain assets and liabilities:
Accounts receivable		(5,309	)		35,863			(29,619	)
Materials, supplies and fuel		4,928			(5,432	)		(7,916	)
Other current assets		6,802			(6,305	)		(1,395	)
Accounts payable		(10,694	)		(47,424	)		60,269
Accrued retirement benefits		(18,721	)		(32,413	)		(46,067	)
Other current liabilities		(13,544	)		38,598			11,267
Risk management assets and liabilities		3,319			(3,622	)		3,673
Other deferred assets		(10,336	)		(51,172	)		(2,164	)
Other regulatory assets		(54,061	)		(50,347	)		(31,790	)
Other deferred liabilities		(25,611	)		24,063			18,873
Net Cash from Operating Activities		485,074			320,862			564,628
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(656,074	)		(1,314,697	)		(750,275	)
Customer advances for construction		(5,281	)		(13,121	)		(1,150	)
Contributions in aid of construction		67,514			52,261			19,576
Investments and other property - net		(21,547	)		2,690			2,768
Net Cash used by Investing Activities		(615,388	)		(1,272,867	)		(729,081	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,065,338			1,437,412			724,391
Retirement of long-term debt		(809,009	)		(585,507	)		(596,339	)
Additional investment by parent company		-			146,600			65,000
Dividends paid		(112,000	)		(54,907	)		(28,231	)
Net Cash from Financing Activities		144,329			943,598			164,821
Net Increase (Decrease) in Cash and Cash Equivalents		14,015			(8,407	)		368
Beginning Balance in Cash and Cash Equivalents		28,594			37,001			36,633
Ending Balance in Cash and Cash Equivalents	$	42,609		$	28,594		$	37,001
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	217,807		$	170,281		$	164,704
Income taxes	$	2		$	15,535		$	6,760
Significant non-cash transactions:
Accrued construction expenses as of December 31,	$	117,226		$	119,608		$	80,284
The accompanying notes are an integral part of the financial statements.

96

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
	Year Ended December 31,
	2009		2008			2007
NET INCOME	$	134,284	$	158,431		$	165,694
OTHER COMPREHENSIVE INCOME (LOSS)
Change in compensation retirement benefits liability and amortization (Net of taxes $(96), $207 and $487 in 2009, 2008 and 2007, respectively)
	$	175	$	(393	)	$	(905	)
OTHER COMPREHENSIVE INCOME (LOSS)	$	175	$	(393	)	$	(905	)
COMPREHENSIVE INCOME	$	134,459	$	151,038		$	164,789
The accompanying notes are an integral part of the financial statements.

97

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(Dollars in Thousands)
	December 31,
	2009			2008			2007
Common Stock:
Balance at Beginning of Year and End of Year	$	1		$	1		$	1
Other Paid-In Capital:
Balance at Beginning of Year		2,254,182			2,107,582			2,042,369
Capital contribution from parent		-			146,600			65,000
Tax Benefit from stock option exercises		7			-			213
Balance at End of Year		2,254,189			2,254,182			2,107,582
Retained Earnings:
Balance at Beginning of Year		377,055			272,435			132,201
Adjustments to beginning balances: Compensation retirement benefits in 2008       (net of taxes of ($1,514)) and uncertain tax positions in 2007		6			(2,811	)		207
Income for the year		134,284			151,431			165,694
Common stock dividends declared		(112,000	)		(44,000	)		(25,667	)
Balance at End of Year		399,345			377,055			272,435
Accumulated Other Comprehensive (Loss):
Balance at Beginning of Year		(3,671	)		(3,278	)		(2,373	)
Change in compensation retirement benefits liability and amortization       (net of taxes of ($96), $207 and $487 in 2009, 2008 and 2007 respectively)		175			(393	)		(905	)
Balance at End of Year		(3,496	)		(3,671	)		(3,278	)
Total Common Shareholder’s Equity at End of Year	$	2,650,039		$	2,627,567		$	2,376,740
The accompanying notes are an integral part of the financial statements.

98

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
	Year ended December 31,
	2009			2008			2007
OPERATING REVENUES:
Electric	$	957,130		$	1,002,674		$	1,038,867
Gas		205,263			209,987			205,430
Total Operating Revenues		1,162,393			1,212,661			1,244,297
OPERATING EXPENSES:
Fuel for power generation		294,121			283,342			242,973
Purchased power		130,977			293,527			348,299
Gas purchased for resale		153,607			170,468			150,879
Deferred energy - electric - net		73,829			1,291			78,044
Deferred energy - gas - net		7,636			(4,609	)		10,763
Other operating expenses		170,849			141,064			142,348
Maintenance		31,290			30,787			31,553
Depreciation and amortization		106,048			89,528			83,393
Taxes other than income		23,447			21,304			20,097
Total Operating Expenses		991,804			1,026,702			1,108,349
OPERATING INCOME		170,589			185,959			135,948
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt:            2009 - $3,044; 2008 - $9,464; 2007 - $12,771)		(69,413	)		(72,712	)		(60,735	)
Interest income (expense) on regulatory items		(5,743	)		(2,087	)		865
AFUDC-equity		3,249			12,524			15,948
Other income		13,276			12,819			8,091
Other expense		(7,648	)		(8,318	)		(8,441	)
Total Other Income (Expense)		(66,279	)		(57,774	)		(44,272	)
Income Before Income Tax Expense		104,310			128,185			91,676
Income tax expense (Note 10)		31,225			37,603			26,009
NET INCOME		73,085			90,582			65,667
The accompanying notes are an integral part of the financial statements.

99

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
		December 31,
		2009		2008
ASSETS
Current Assets:
Cash and cash equivalents		$	14,359	$	21,411
Accounts receivable less allowance for uncollectible accounts:
	2009 - $2,966; 2008 - $2,262		146,883		171,729
Materials, supplies and fuel, at average cost			54,802		50,132
Risk management assets (Note 9)			5,656		4,394
Intercompany income taxes receivable			19,315		64,932
Deferred income taxes (Note 10)			46,414		12,253
Other current assets			16,056		17,631
Total Current Assets			303,485		342,482
Utility Property:
Plant in service			3,419,190		3,291,708
Construction work-in-progress			89,102		91,067
Total			3,508,292		3,382,775
Less accumulated provision for depreciation			1,156,489		1,102,785
Total Utility Property, Net			2,351,803		2,279,990
Investments and other property, net (Note 4)			5,428		403
Deferred Charges and Other Assets:
Regulatory assets (Note 3)			362,009		443,932
Regulatory asset for pension plans (Note 3)			130,283		218,550
Risk management assets (Note 9)			1,142		2,613
Other deferred charges and assets			40,837		33,959
Total Deferred Charges and Other Assets			534,271		699,054
Assets Held for Sale (Note 16)			147,158		142,506
TOTAL ASSETS		$	3,342,145	$	3,464,435
(Continued)

100

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
	December 31,
	2009			2008
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt (Note 6)	$	15,000		$	600
Accounts payable		76,867			109,410
Accounts payable, affiliated companies		21,091			17,433
Accrued expenses		34,185			37,787
Dividends declared		-			96,800
Risk management liabilities (Note 9)		27,749			90,990
Deferred energy (Note 3)		117,276			28,546
Other current liabilities		14,996			14,298
Total Current Liabilities		307,164			395,864
Long-term debt (Note 6)		1,282,225			1,395,987
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes (Note 10)		350,802			287,251
Deferred investment tax credit		13,843			15,922
Accrued retirement benefits		104,854			180,209
Risk management liabilities (Note 9)		1,068			18,162
Regulatory liabilities (Note 3)		175,732			161,817
Other deferred credits and liabilities		71,452			107,162
Total Deferred Credits and Other Liabilities		717,751			770,523
Liabilities Held for Sale (Note 16)		25,747			24,100
Shareholder's Equity:
Common stock		4			4
Other paid-in capital		1,111,260			1,020,960
Retained earnings		(99,601	)		(140,685	)
Accumulated other comprehensive loss		(2,405	)		(2,318	)
Total Shareholder's Equity		1,009,258			877,961
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	3,342,145		$	3,464,435
The accompanying notes are an integral part of the financial statements.
(Concluded)

101

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
	For the Year Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	73,085		$	90,582			$	65,667
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		106,048			89,528				83,393
Deferred taxes and deferred investment tax credit		32,548			24,598				(36,713	)
AFUDC-equity		(3,249	)		(12,524	)			(15,948	)
Deferred energy		89,777			(1,494	)			90,595
Other, net		30,368			22,872				29,451
Changes in certain assets and liabilities:
Accounts receivable		68,435			(59,701	)			10,092
Materials, supplies and fuel		(4,436	)		(2,453	)			(5,809	)
Other current assets		1,575			(376	)			2,839
Accounts payable		(15,071	)		(574	)			15,010
Accrued retirement benefits		(2,227	)		(47,923	)			(25,248	)
Other current liabilities		(3,038	)		3,673				11,196
Risk management assets and liabilities		1,739			(1,302	)			6,415
Other deferred assets		(3,495	)		(702	)			2,662
Other regulatory assets		(15,876	)		(17,113	)			(14,074	)
Other deferred liabilities		(30,388	)		31,536				(5,349	)
Net Cash from Operating Activities		325,795			118,627				214,179
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(187,058	)		(220,806	)			(415,242	)
Customer advances for construction		(3,088	)		1,140				9,380
Contributions in aid of construction		9,426			10,260				12,590
Investments and other property - net		(5,017	)		1,611				39
Net Cash used by Investing Activities		(185,737	)		(207,795	)			(393,233	)
CASH FLOWS (USED BY) FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		353,534			697,739				521,992
Retirement of long-term debt		(462,144	)		(489,434	)			(423,155	)
Investment by parent company		90,300			20,000				65,000
Dividends paid		(128,800	)		(141,533	)			(14,236	)
Net Cash (used by) from Financing Activities		(147,110	)		86,772				149,601
Net Decrease in Cash and Cash Equivalents		(7,052	)		(2,396	)			(29,453	)
Beginning Balance in Cash and Cash Equivalents		21,411			23,807				53,260
Ending Balance in Cash and Cash Equivalents	$	14,359		$	21,411			$	23,807
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	69,966		$	72,443			$	59,496
Income taxes	$	12		$	19			$	64
Significant non-cash transactions:
Accrued construction expenses as of December 31,	$	10,560		$	24,374			$	30,879
The accompanying notes are an integral part of the financial statements.

102

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
	Year Ended December 31,
	2009			2008			2007
NET INCOME	$	73,085		$	90,582		$	65,667
OTHER COMPREHENSIVE INCOME (LOSS)
Change in compensation retirement benefits liability and amortization (Net of taxes $48, $126 and $620 in 2009, 2008 and 2007, respectively)
	$	(87	)	$	(234	)	$	(1,153	)
OTHER COMPREHENSIVE LOSS	$	(87	)	$	(234	)	$	(1,153	)
COMPREHENSIVE INCOME	$	72,998		$	90,348		$	64,514
The accompanying notes are an integral part of the financial statements.

103

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(Dollars in Thousands)
	December 31,
	2009			2008			2007
Common Stock:
Balance at Beginning of Year
and End of Year	$	4		$	4		$	4
Other Paid-In Capital:
Balance at Beginning of Year		1,020,960			1,000,595			935,453
Capital contribution from parent		90,300			20,000			65,000
Tax Benefit from stock option exercises		-			365			142
Balance at End of Year		1,111,260			1,020,960			1,000,595
Retained Earnings (Deficit):
Balance at Beginning of Year		(140,685	)		3,325			(49,789	)
Adjustments to beginning balances: Compensation retirement benefits in 2008       (net of taxes of ($857)), and uncertain tax positions in 2007		(1	)		(1,592	)		280
Income for the year		73,085			90,582			65,667
Common stock dividends declared		(32,000	)		(233,000	)		(12,833	)
Balance at End of Year		(99,601	)		(140,685	)		3,325
Accumulated Other Comprehensive Loss:
Balance at Beginning of Year		(2,318	)		(2,084	)		(931	)
Change in compensation retirement benefits liability and amortization       (net of taxes of ($19), $126 and $620 in 2009, 2008 and 2007 respectively)		(87	)		(234	)		(1,153	)
Balance at End of Year		(2,405	)		(2,318	)		(2,084	)
Total Common Shareholder’s Equity at End of Year	$	1,009,258		$	877,961		$	1,001,840
The accompanying notes are an integral part of the financial statements.

104

NOTES TO FINANCIAL STATEMENTS

NOTE 1.                      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Energy Company dba e·three, Sierra Pacific Energy Company, Sierra Water Development Company, NVE Insurance and Sierra Gas Holding Company.  All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

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

In the past, the financial statements for NVE and the Utilities were presented in a traditional utility format; however, many utilities have partially or completely departed from the traditional utility format.  As a result, NVE and the Utilities elected to present current and prior period financial statements and related financial data in a similar commercial format and have reclassified prior year information to conform with the current period presentation.  The change in format did not have an effect on net income.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada.  The assets of NPC represent approximately 71% of the consolidated assets of NVE at December 31, 2009.  NPC provides electricity to approximately 827,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base.  Service is also provided to the Department of Energy’s Nevada Test Site in Nye County.  The consolidated financial statements of NVE include NPC’s wholly-owned subsidiary, NEICO.

SPPC is an operating public utility that provides electric service in northern Nevada and northeastern California.  SPPC also provides natural gas service in the Reno/Sparks area of Nevada.  The assets of SPPC represent approximately 29% of the consolidated assets of NVE at December 31, 2009.  SPPC provides electricity to approximately 367,000 customers in a 50,000 square mile service area including western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City and Elko, and a portion of eastern California, including the Lake Tahoe area.  SPPC also provides natural gas service in Nevada to approximately 151,000 customers in an area of about 800 square miles in the Reno and Sparks areas.  The consolidated financial statements of SPPC include the accounts of SPPC’s wholly-owned subsidiaries, PPC, PPIC, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I.

The Utilities’ accounts for electric operations and SPPC’s accounts for gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are currently subject to the approval of the PUCN and, in the case of SPPC, rates are also subject to the approval of the CPUC and are designed to recover the cost of providing generation, transmission and distribution services.  As a result, the Utilities qualify for the application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC.  This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the deferral of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs.  The accounting guidance prescribes the method to be used to record the financial transactions of a regulated entity.  The criteria for applying the accounting for regulated operations include the following: (i) rates are set by an independent third party regulator; (ii) regulated rates are designed to recover the specific costs of the regulated products or services; and (iii) it is reasonable to assume that rates are set at levels that recovered costs can be charged to and collected from customers.  Management periodically assesses whether the requirements for application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC are satisfied.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers.  If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets.  Management believes the existing regulatory assets are probable of recovery either because the Utilities received prior PUCN approval or due to regulatory precedent set for similar circumstances.  Included in Note 3, Regulatory Actions, are details of other regulatory assets and liabilities, and their current regulatory treatment.

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Equity Carrying Charges

In accordance with various regulatory orders, the Utilities’ record carrying charges as allowed by the Regulated Operations Topic of the FASC.  However, for financial reporting purposes the amounts representing equity carrying charges are not recognized until collected through regulated rates.  As of December 31, 2009, NPC and SPPC have accumulated approximately $2.5 million and $0.5 million, respectively (excluding the carrying charge on the Lenzie Generating Station as discussed below), of equity related carrying charges that will be recognized into income when the corresponding regulatory assets are collected through rates.  For further information, see Note 3, Regulatory Actions, of the Notes to Financial Statements, Other Regulatory Assets table.

   Carrying Charge on the Lenzie Generating Station

In 2004, the PUCN granted NPC’s request to designate the Lenzie Generating Station as a critical facility and allowed a 2% enhanced ROE to be applied to the Lenzie Generating Station construction costs expended after acquisition.  The order allowed for an additional 1% enhanced ROE if the two Lenzie Generating Station units were brought on line early.  In addition, the PUCN granted NPC’s request to begin accumulating a carrying charge as a regulatory asset including the 3% enhanced ROE (collectively referred to as “carrying charges”), until the plant is included in rates.  Units 1 and 2 were declared commercially operable in January 2006 and April 2006, respectively, qualifying for the incentive ROE treatment.

Through June 30, 2007, NPC had accumulated approximately $57.6 million in carrying charges; however, as of December 31, 2009 $7.7 million of this amount was not recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through rates.  NPC did not record a separate carrying charge component related to the Lenzie Generating Station during 2009 as the plant is in rate base effective June 1, 2007, as discussed below.

In May 2007, the PUCN issued its order on NPC’s 2006 GRC authorizing recovery of the carrying charges, effective as of June 1, 2007.  NPC was authorized to recover over a 35 year period $30.3 million of the carrying charges calculated through the certification period ending October 31, 2006.  Beginning June 1, 2007, NPC began recognizing its full return on the Lenzie Generating Station through rates rather than as a separate carrying charge component.  In June 2009, as a result of its 2008 GRC, the PUCN authorized recovery of the remaining $27.3 million in carrying charges over the life of the asset.

Deferred Energy Accounting

Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures.  The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased gas, fuel and purchased power.

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet in accordance with the provisions of the Regulated Operations Topic of the FASC.  Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs.  These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review.

Nevada law requires the Utilities file annual DEAA applications and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.”  Nevada law also specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity and to purchase energy.  The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances.  See Note 3, Regulatory Actions for details regarding deferred energy balances.

Utility Plant

The cost of additions, including betterments and replacements of units of property, are charged to utility plant.  When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation.  The cost of current repairs and minor replacements are charged to maintenance expense when incurred, with the exception of long term service agreements.  These agreements may have annual payment amounts for repairs which could vary over the life of the agreement between maintenance expense and amounts to be capitalized.  To ensure consistency in annual expense for rate making purposes, the amounts to be charged to maintenance expense are smoothed over the life of the contract, with an offset to a regulatory asset or liability account.  Amounts prepaid for capital expenditure are recorded in a prepaid asset account.

In addition to direct labor and material costs, certain other direct and indirect costs are capitalized.  The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative and supervision employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, post retirement and post employment benefits, vacations and payroll taxes; and an AFUDC which includes the cost of debt and equity capital associated with construction activity.

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AFUDC

As part of the cost of constructing utility plant, the Utilities capitalize AFUDC.  AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN.  AFUDC is capitalized in the same manner as construction labor and material costs, however, with an offsetting credit to “other income” for the portion representing the cost of equity funds; and as a reduction of interest charges for the portion representing borrowed funds.  Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices.  Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all capital costs.  This is accomplished by including such costs in the rate base and in the provision for depreciation.  NPC’s AFUDC rate used during 2009 was 8.57% and 2008 and 2007 was 9.06%.  SPPC’s AFUDC rates used during 2009, 2008 and 2007 were 7.96%, 8.54% and 8.60%, respectively.  As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific interest-rate financings directly associated with those projects.

Depreciation

Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC.  Depreciation expense is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases.  NPC’s depreciation provision, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, was approximately 2.74%, 2.56%, and 2.66% during 2009, 2008 and 2007, respectively.  SPPC’s depreciation provision for 2009, 2008 and 2007, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 3.07%, 2.77% and 3.01%, respectively.

The average estimated useful life for each major class of utility property, plant and equipment are as follows:

	Estimated Useful Lives
	NPC	SPPC
Electric Generation	30 to 125 years	30 to 125 years
Electric Transmission	35 to 60 years	50 to 70 years
Electric Distribution	25 to 65 years	33 to 65 years
Gas Distribution	N/A	28 to 65 years
General Plant	5 to 50 years	5 to 45 years

 Impairment of Long-Lived Assets

NVE, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in the Property, Plant and Equipment Topic of the FASC.

Cash and Cash Equivalents

Cash is comprised of cash on hand and working funds.  Cash equivalents consist of high quality investments in money market funds and do not have any withdrawal restrictions.

Federal Income Taxes

NVE and the Utilities file a consolidated federal income tax return.  Current income taxes are allocated based on NVE’s and each Utilitiy’s respective taxable income or loss and tax credits as if each Utility filed a separate return.

NVE and the Utilities recognize deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns.  Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.  Deferred tax assets are also recorded for deductions incurred and credits earned that have not been utilized in tax returns filed or to be filed for tax years through the date of the financial statements.  Management considers estimates of the amount and character of future taxable income by tax jurisdiction in assessing the likelihood of realization of deferred tax assets.  If it is not more likely than not that a deferred tax asset will be realized in its entirety, a valuation allowance is recorded with respect to the portion estimated not likely to be realized.

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.  NVE and the Utilities classify interest and penalties associated with unrecognized tax

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benefits as interest and other expense, respectively, within the income statement.  No interest expense or penalties associated with unrecognized tax benefits have been recorded.   

 The Utilities reduce rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses are recognized for financial reporting purposes. A regulatory asset is recorded for these amounts to reflect the future increases in income taxes payable that will be recovered from customers when these temporary differences reverse. The Utilities have been fully normalized since 1987. AFUDC-equity is recorded on an after-tax basis. Accordingly, a regulatory asset is recorded when AFUDC-equity is recognized. This regulatory asset reverses as the related plant is depreciated, resulting in an increase to the tax provision.

 The Utilities also record regulatory liabilities for obligations to reduce rates charged customers for deferred taxes recovered from customers in prior years at corporate tax rates higher than the current tax rates. The reduction in rates charged customers will occur as the temporary differences resulting in the excess deferred tax liabilities reverse.

 Investment tax credits are deferred and amortized over the estimated service lives of the related properties.

Revenues

 Operating revenues include billed and unbilled utility revenues.  The accrual for unbilled revenues represents amounts owed to the Utilities for service provided to customers for which the customers have not yet been billed.  These unbilled amounts are also included in accounts receivable.  Reference NPC’s 2008 GRC for further discussion of the deferred rate increase in Note 3, Regulatory Actions, of the Notes to Financial Statements.

 Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered.  At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated.  These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns, line loss and the Utilities’ current tariffs.  Accounts receivable as of December 31, 2009, include unbilled receivables of $103 million and $78 million for NPC and SPPC, respectively.  Accounts receivable as of December 31, 2008, include unbilled receivables of $103 million and $76 million for NPC and SPPC, respectively.

Asset Retirement Obligations

 The Asset Retirement and Environmental Liabilities Topic of the FASC provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets.  Under the accounting guidance, these liabilities are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets.  Accretion of the liabilities due to the passage of time is classified as an operating expense.  Retirement obligations associated with long-lived assets included within the scope of the accounting guidance are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel.  NVE, NPC and SPPC adopted the provisions of this accounting guidance on January 1, 2003.

 Management’s methodology to assess its legal obligation included an inventory of assets by company, system and components and a review of rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws.  Management identified a legal obligation to retire generation plant assets specified in land leases for NPC’s jointly-owned Navajo Generating Station and the newly acquired Higgins Generating Station.  Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases.

 In March, 2005, the FASB issued additional guidance related to the Asset Retirement and Environmental Liabilities Topic of the FASC.   The updated guidance was effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year enterprises).   The updated accounting guidance clarified the term conditional retirement obligation as well as when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

 Similar to the methodology used to assess legal obligations, management reviewed the inventory of assets by system and components, as well as rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws.  Management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl to have met the conditional asset retirement obligations as defined in the Asset Retirement and Environmental Liabilities Topic of the FASC.

 The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligation for the years presented below (dollars in thousands):

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		NVE						NPC						SPPC
		2009			2008			2009			2008			2009			2008
Balance at January 1	$	57,627		$	53,462		$	50,216		$	46,270		$	7,411		$	7,192
Liabilities incurred in current period		7,888			3,424			7,888			3,162			-			262
Liabilities settled in current period		-			(4,160	)		-			(4,160	)		-			-
Accretion expense		4,258			2,904			3,776			2,503			482			401
Revision in estimated cash flows		(13,805	)		1,997			(13,560	)		2,441			(245	)		(444	)
Balance at December 31	$	55,968		$	57,627		$	48,320		$	50,216		$	7,648		$	7,411

Cost of Removal

In addition to the legal asset retirement obligations booked under the accounting guidance for asset retirement obligations, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets.  The amounts of such accruals included in regulatory liabilities in 2009 are approximately $192.9 million and $166.7 million for NPC and SPPC, respectively.  In 2008, the amounts were approximately $174.3 million and $150.5 million.

Variable Interest Entities

The FASC Consolidation guidance provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity.   To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with QFs, jointly owned facilities and partnerships that are not consolidated.  The Utilities identified seven QFs with long-term purchase power contracts that are variable interests.  However, the Utilities are not required at this time to consolidate these QFs under the scope exception provided for in FASC Consolidation guidance due to the inability to obtain information necessary to (1) determine whether the entity is a variable interest entity, (2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3) perform the accounting required to consolidate the variable interest entity for which it is determined to be the primary beneficiary.  The Utilities have requested financial information from these QFs but have not been successful in obtaining the information.  The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs 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.  The Utilities have not identified any other significant variable interests that require consolidation as of December 31, 2009.  Furthermore, as discussed under Recent Pronouncements, NVE and the Utilities will adopt the FASC Consolidation accounting guidance for variable interest entities effective January 1, 2010, but do not expect the adoption to have a material impact on the consolidated financial statements.

Franchise Fees and Universal Energy Charges

NPC and SPPC, as agents for some state and local governments collect from customers franchise fees and universal energy charges (UEC) levied by the state or local governments on our customers.  NPC and SPPC do not record these fees or charges as revenue or expense.

Recent Accounting Standards Updates

   FASC and the Hierarchy of Generally Accepted Accounting Principles

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

   Fair Value Measurements and Disclosures

In February 2008, the FASB issued transition guidance which deferred the effective date of applying fair value measurements to nonfinancial assets and nonfinancial liabilities which are nonrecurring.  The transition guidance was effective for NVE and the Utilities beginning January 1, 2009.  The adoption of this guidance did not have a material impact on the consolidated financial statements of NVE and the Utilities.

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

In August 2009, the FASB issued an update on the Fair Value Measurements and Disclosures Topic as reflected in the FASB Accounting Standards Codification for the fair value of liabilities.  This update provides clarification on measuring liabilities at fair

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value when a quoted price in an active market is not available.  The provisions of this guidance were effective for NVE and the Utilities beginning October 1, 2009.  The adoption of this guidance did not have a significant impact on the consolidated financial statements.

In September 2009, the FASB issued an update on the Fair Value Measurements and Disclosures Topic as reflected in the FASB Accounting Standards Codification for the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent). The guidance permits a reporting entity to measure the fair value of an investment within its scope on the basis of net asset value per share of the investment (or its equivalent).  NVE and the Utilities adopted the accounting update as of December 31, 2009. See Note 11, Retirement Plan and Post-Retirement Benefits.

In January 2010, the FASB issued an update on the Fair Value Measurements and Disclosure Topic as reflected in the FASB Accounting Standards Codification for recurring and nonrecurring fair value measurements. 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 guidance 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.  NVE and the Utilities do not expect the adoption to have a significant impact on their disclosure requirements.

   Derivatives and Hedging

In March 2008, the FASB issued an amendment of its existing guidance effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.  The purpose of the amendment is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows.  NVE and the Utilities adopted the amendment beginning January 1, 2009.  See Note 9, Derivatives and Hedging Activities.

   Subsequent Events

In May 2009, the FASB issued guidance which establishes the accounting principles and disclosure requirements for subsequent events.  The guidance requires an entity to disclose the date through which subsequent events have been evaluated, as well as whether that date is the date the financial statements were issued or the date the financial statements were available to be issued.  NVE and the Utilities evaluated subsequent events at the time the financial statements were issued, which was February 22, 2010.  The guidance was effective for NVE and the Utilities as of June 30, 2009.

   Consolidations of Variable Interest Entities

In June 2009, the FASB amended existing guidance related to the Consolidation of Variable Interest Entities.  The amendment requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity.  This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics:  a) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. The amendment will be effective for NVE and the Utilities beginning January 1, 2010.  Although NVE and the Utilities have substantially completed their evaluation of the impacts of this statement, at this time, NVE and the Utilities do not believe the adoption will have a material impact on the consolidated financial statements.

   Compensation-Retirement Benefits

In December 2008, the FASB amended existing guidance related to the Compensation-Retirement Benefits Topic of the FASC. The amended guidance requires enhanced disclosures about plan assets of a defined benefit pension or other postretirement plan. The provisions of the accounting guidance are effective for NVE and the Utilities as of December 31, 2009. See Note 11, Retirement Plan and Post-Retirement Benefits.

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NOTE 2.                      SEGMENT INFORMATION

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

In the past, the financial statements for NVE and the Utilities were presented in a traditional utility format; however, many utilities have partially or completely departed from the traditional utility format.  As a result, NVE and the Utilities elected to present current and prior period financial statements and related financial data in a similar commercial format  and have reclassified prior year information to conform with the current period presentation.  The change in format did not have an effect on net income.

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 fuel, purchased power, and deferred 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.  SPPC's deferred energy costs-net for the year ended December 31, 2007 include $14.2 million of disallowed energy costs (dollars in thousands):

								SPPC
	NPC		SPPC		SPPC			Reconciling	SPPC		NVE			NVE
December 31, 2009	Electric		Electric		Gas			Eliminations(1)	Total		Other			Consolidated
Operating Revenues	$	2,423,377	$	957,130	$	205,263			$	1,162,393	$	28		$	3,585,798
Energy Costs:
Fuel for power generation		587,647		294,121		-				294,121		-			881,768
Purchased Power		627,759		130,977		-				130,977		-			758,736
Gas purchased for resale		-		-		153,607				153,607		-			153,607
Deferred energy - net		207,611		73,829		7,636				81,465		-			289,076
		1,423,017		498,927		161,243				660,170		-			2,083,187
Gross Margin	$	1,000,360	$	458,203	$	44,020			$	502,223	$	28		$	1,502,611
Other operating expense		279,865								170,849		2,699			453,413
Maintenance		71,019								31,290		-			102,309
Depreciation and amortization		215,873								106,048		-			321,921
Taxes other than income		37,241								23,447		197			60,885
Operating Income	$	396,362							$	170,589	$	(2,868	)	$	564,083
Assets	$	8,096,371	$	2,997,116	$	305,434	$	39,595	$	3,342,145	$	(25,053	)	$	11,413,463
Capital expenditures	$	656,074	$	171,036	$	16,022			$	187,058				$	843,132

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									SPPC
	NPC			SPPC		SPPC			Reconciling	SPPC			NVE			NVE
December 31, 2008	Electric			Electric		Gas			Eliminations(1)	Total			Other			Consolidated
Operating Revenues	$	2,315,427		$	1,002,674	$	209,987			$	1,212,661		$	25		$	3,528,113
Energy Costs:
Fuel for power generation		755,925			283,342		-				283,342						1,039,267
Purchased Power		680,816			293,527		-				293,527						974,343
Gas purchased for resale		-			-		170,468				170,468						170,468
Deferred energy - net		(6,947	)		1,291		(4,609	)			(3,318	)					(10,265	)
		1,429,794			578,160		165,859				744,019						2,173,813
Gross Margin	$	885,633		$	424,514	$	44,128			$	468,642		$	25		$	1,354,300
Other operating expense		249,236									141,064			3,719			394,019
Maintenance		63,282									30,787						94,069
Depreciation and amortization		171,080									89,528						260,608
Taxes other than income		32,069									21,304			152			53,525
Operating Income	$	369,966								$	185,959		$	(3,846	)	$	552,079
Assets	$	7,904,147		$	3,113,539	$	315,095	$	35,801	$	3,464,435		$	(20,712	)	$	11,347,870
Capital expenditures	$	1,314,697		$	202,011	$	18,795			$	220,806					$	1,535,503

								SPPC
	NPC		SPPC		SPPC			Reconciling	SPPC		NVE			NVE
December 31, 2007	Electric		Electric		Gas			Eliminations(1)	Total		Other			Consolidated
Operating Revenues	$	2,356,620	$	1,038,867	$	205,430			$	1,244,297	$	43		$	3,600,960
Energy Costs:
Fuel for power generation		594,382		242,973		-				242,973					837,355
Purchased  Power		688,606		348,299		-				348,299					1,036,905
Gas purchased for resale		-		-		150,879				150,879					150,879
Deferred energy - net		233,166		78,044		10,763				88,807					321,973
		1,516,154		669,316		161,642				830,958		-			2,347,112
Gross Margin	$	840,466	$	369,551	$	43,788			$	413,339	$	43		$	1,253,848
Other operating expense		232,610								142,348		4,488			379,446
Maintenance		67,482								31,553		-			99,035
Depreciation and amortization		152,139								83,393		-			235,532
Taxes other than income		29,823								20,097		193			50,113
Operating Income	$	358,412							$	135,948	$	(4,638	)	$	489,722
Assets	$	6,377,369	$	2,669,312	$	273,220	$	37,361	$	2,979,893	$	110,857		$	9,468,119
Capital expenditures	$	750,275	$	379,692	$	35,550			$	415,242				$	1,165,517

(1)The reconciliation of segment assets at December 31, 2009, 2008, and 2007 to the consolidated total includes the following unallocated amounts:

	2009		2008		2007
Other investments	$	5,428	$	-	$	-
Cash		14,359		21,411		23,807
Deferred charges-other		19,808		14,390		13,554
	$	39,595	$	35,801	$	37,361

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NOTE 3.                      REGULATORY ACTIONS

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations.  Additionally, under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC.  The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission.

As a result of regulation, the Utilities are required to file annual electric and gas DEAA cases by March 1, quarterly BTER updates for the Utilities’ electric and gas departments and triennial GRCs.  A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER updates recover current energy costs.  A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.  Detailed below are Deferred Energy Costs which relate to the DEAA and BTER filings and further below are other regulatory assets and liabilities which primarily relate to the GRCs.  Additionally, significant pending or settled rate cases are discussed below.

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

	December 31, 2009
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total
Nevada Deferred Energy
Cumulative Balance authorized in 2009 DEAA	$	74,885	(1)	$	(24,870	)	$	(8,733	)	$	41,282
2009 Amortization		171			5,817			3,128			9,116
2009 Deferred Energy Over Collections (2)		(173,782	)		(81,227	)		(11,391	)		(266,400	)
Nevada Deferred Energy Balance at December 31, 2009 - Subtotal		(98,726			(100,280	)		(16,996	)		(216,002	)
Cumulative CPUC balance		-			842			-			842
Western Energy Crisis Rate Case(effective 6/07, 3 years)		16,263			-			-			16,263
Reinstatement of deferred energy (effective 6/07, 10 years)		147,297			-			-			147,297
Total	$	64,834		$	(99,438	)	$	(16,996	)	$	(51,600	)
Current Assets
Other deferred charges (3)		-			842			-			842
Deferred Assets
Deferred energy		138,963			-			-			138,963
Current Liabilities
Deferred energy		(74,129	)		(100,280	)		(16,996	)		(191,405	)
Total	$	64,834		$	(99,438	)	$	(16,996	)	$	(51,600	)

(1)	These deferred costs include PUCN ordered adjustments and will be included as an offset to 2009 Deferred Energy Over-Collections within the February 2010 DEAA filings.
(2)	These deferred over collections are to be requested in February 2010 DEAA filings, and include PUCN ordered adjustments.
(3)	Refer to Note 16, Assets Held For Sale.

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	December 31, 2008
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total
Nevada Deferred Energy
Cumulative Balance requested in 2008 DEAA	$	35,500	(1)	$	(21,043	)	$	(11,382	)	$	3,075
2008 Amortization		(89,659	)		(13,100	)		993			(101,766	)
2008 Deferred Energy (2)		130,597			14,330			1,656			146,583
Nevada Deferred Energy Balance at December 31, 2008 - Subtotal	$	76,438		$	(19,813	)	$	(8,733	)	$	47,892
Cumulative CPUC balance		-			1,890			-			1,890
Western Energy Crisis Rate Case(effective 6/07, 3 years)		41,704			-			-			41,704
Reinstatement of deferred energy (effective 6/07, 10 years)		163,321			-			-			163,321
Total	$	281,463		$	(17,923	)	$	(8,733	)	$	254,807
Current Assets
Other deferred charges (3)		50,436			1,890			-			52,326
Deferred Assets
Deferred energy		231,027			-			-			231,027
Current Liabilities
Deferred energy		-			(19,813	)		(8,733	)		(28,546	)
Total	$	281,463		$	(17,923	)	$	(8,733	)	$	254,807

(1)	These deferred costs include PUCN ordered adjustments.
(2)	These deferred costs were requested in February 2009 DEAA filings.
(3)	Refer to Note 16, Assets Held For Sale.

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As discussed in Note 1, Summary of Significant Accounting Policies, regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers.  If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets.  Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any current, pending or potential legislation.  Detailed below are Other Regulatory Assets and Liabilities included in the balance sheet of NVE, NPC and SPPC and their current regulatory treatment.

NV ENERGY, INC.
OTHER REGULATORY ASSETS AND LIABILITIES
	AS OF DECEMBER 31, 2009
		Receiving Regulatory Treatment
(dollars in thousands) DESCRIPTION	Remaining Amortization Period	Earning a Return(1)		Not Earning a Return		Pending Regulatory Treatment			2009 Total		As of December 31, 2008 Total
Regulatory assets
Loss on reacquired debt	Term of Related Debt	$	81,951	$	-	$	-		$	81,951	$	87,381
Income taxes	Various		-		261,633		-			261,633		264,779
Risk management			-		48,586		-			48,586		360,000
Lenzie Generating Station	2042		-		75,949		-			75,949		77,616
Mohave Generating Station and deferred costs	2015		14,456		-		6,620	(2)		21,076		19,090
Clark Generating Station Units  1-3	2012		4,252		10,136		-			14,388		18,689
Piñon Pine	Various thru 2029		30,521		8,969		1,445	(2)		40,935		42,953
Plant assets	Various thru 2031		2,332		-		1,302	(2)		3,634		2,971
Asset retirement obligations					-		51,916	(2)		51,916		43,812
Nevada divestiture costs	2012		10,442		-		-			10,442		14,955
Merger transition/transaction costs	2016		-		17,186		-			17,186		21,096
Merger severance/relocation	2016		-		9,518		-			9,518		11,640
Merger goodwill	2046		-		269,697		-			269,697		277,531
California restructure costs			-		-		-			-		220
Conservation programs	Thru 2015		93,550		-		82,170	(3)		175,720		125,940
Renewable energy programs			-		-		-			-		4,042
Legal costs					-		-			-		6,044
Peabody coal costs			-		17,366		-			17,366		17,126
Deferred Rate Increase			-		-		95,483	(4)		95,483		-
Legal fees-Western Energy Crisis	2010		697		-		-			697		1,788
Union contract OPEB change	2017		-		-		9,275	(2)		9,275		10,155
Impact Fees	2011		210		-		4,791	(2)		5,001		2,040
Obsolete Inventory			-		-		2,828	(2)		2,828		746
Other costs	Thru 2017		241		5,256		-			5,497		4,672
Subtotal		$	238,652	$	724,296	$	255,830		$	1,218,778	$	1,415,286
Pensions			-		264,892		-			264,892		413,544
Total regulatory assets		$	238,652	$	989,188	$	255,830		$	1,483,670	$	1,828,830

Regulatory liabilities
Cost of removal	Various	$	348,150	$	-	$	-		$	348,150	$	315,753
Income taxes	Various		-		22,128		-			22,128		25,479
Gain on property sales			-		-		-			-		(643	)
SO2 allowances	Various thru 2015		499		-		-			499		696
Depreciation-customer advances	2011		5,476		-		268	(2)		5,744		-
Renewable energy programs	2011		7,236		-		-			7,236		7,938
Domestic production tax deduction			-		-		-			-		943
Impact Fees			-		-		1,120	(2)		1,120		-
Other			-		-		1,142	(2)		1,142		360
Total regulatory liabilities		$	361,361	$	22,128	$	2,530		$	386,019	$	350,526

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	NEVADA POWER COMPANY
	OTHER REGULATORY ASSETS AND LIABILITIES
	AS OF DECEMBER 31, 2009
		Receiving Regulatory Treatment
(dollars in thousands) DESCRIPTION	Remaining Amortization Period	Earning a Return(1)		Not Earning a Return		Pending Regulatory Treatment			2009 Total		As of December 31, 2008 Total
Regulatory assets
Loss on reacquired debt	Term of Related Debt	$	45,229	$	-	$	-		$	45,229	$	55,659
Income taxes	Various		-		173,336		-			173,336		169,506
Risk management			-		23,334		-			23,334		252,884
Lenzie Generating Station	2042		-		75,949		-			75,949		77,616
Mohave Generating Station and  deferred costs	2015		14,456		-		6,620	(2)		21,076		19,090
Clark Generating Station Units 1-3	2012		4,252		10,136		-			14,388		18,689
Asset retirement obligations			-		-		46,323	(2)		46,323		38,847
Nevada divestiture costs	2012		6,285		-		-			6,285		9,078
Merger transition/transaction costs	2014		-		11,863		-			11,863		14,655
Merger severance/relocation	2014		-		4,336		-			4,336		5,356
Merger goodwill	2044		-		169,536		-			169,536		174,486
Conservation programs	2015		87,606		-		57,288	(3)		144,894		104,608
Renewable energy programs			-		-		-			-		1,932
Peabody coal costs			-		17,366		-			17,366		17,126
Deferred Rate Increase			-		-		95,483	(4)		95,483		-
Legal costs			-		-					-		6,044
Legal fees-Western Energy Crisis	2010		697		-		-			697		1,788
Obsolete Inventory			-		-		2,062	(2)		2,062		518
Other costs	2012		-		4,612		-			4,612		3,472
Subtotal		$	158,525	$	490,468	$	207,776		$	856,769	$	971,354
Pensions			-		129,709		-			129,709		187,894
Total regulatory assets		$	158,525	$	620,177	$	207,776		$	986,478	$	1,159,248
Regulatory liabilities
Cost of removal	Various	$	192,944	$	-	$	-		$	192,944	$	174,262
Income taxes	Various		-		7,149		-			7,149		8,713
SO2 allowances	Various thru 2015		499		-		-			499		696
Depreciation-customer advances	2012		3,113		-		-			3,113		3,735
Renewable energy programs	2011		4,320		-		-			4,320		-
Domestic production tax deduction					-					-		943
Impact Fees			-		-		1,120	(2)		1,120		-
Other			-		-		1,142	(2)		1,142		360
Total regulatory liabilities		$	200,876	$	7,149	$	2,262		$	210,287	$	188,709

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	SIERRA PACIFIC POWER COMPANY
	OTHER REGULATORY ASSETS AND LIABILITIES
	AS OF DECEMBER 31, 2009
		Receiving Regulatory Treatment
(dollars in thousands) DESCRIPTION	Remaining Amortization Period	Earning a Return(1)		Not Earning a Return		Pending Regulatory Treatment			2009 Total		As of December 31, 2008 Total
Regulatory assets
Loss on reacquired debt	Term of Related Debt	$	36,722	$	-	$	-		$	36,722	$	31,722
Income taxes	Various		-		88,297		-			88,297		95,273
Risk management			-		25,252		-			25,252		107,116
Piñon Pine	Various thru 2029		30,521		8,969		1,445	(2)		40,935		42,953
Plant assets	Various thru 2031		2,332		-		1,302	(2)		3,634		2,971
Asset retirement obligations			-		-		5,593	(2)		5,593		4,965
Nevada divestiture costs	2012		4,157		-		-			4,157		5,877
Merger transition/transaction costs	2016		-		5,323		-			5,323		6,441
Merger severance/relocation	2016		-		5,182		-			5,182		6,284
Merger goodwill	2046		-		100,161		-			100,161		103,045
California restructure costs					-		-			-		220
Conservation programs	Thru 2014		5,944		-		24,882	(3)		30,826		21,332
Renewable energy programs			-		-		-			-		2,110
Union contract OPEB change	2017		-		-		9,275	(2)		9,275		10,155
Legal fees-Western Energy Crisis					-					-		-
Impact Fees	2011		210		-		4,791	(2)		5,001		2,040
Obsolete Inventory			-		-		766	(2)		766		228
Other costs	Various thru 2017		241		644		-			885		1,200
Subtotal		$	80,127	$	233,828	$	48,054		$	362,009	$	443,932
Pensions			-		130,283		-			130,283		218,550
Total regulatory assets		$	80,127	$	364,111	$	48,054		$	492,292	$	662,482
Regulatory liabilities
Cost of removal	Various	$	155,206	$	-	$	-		$	155,206	$	141,491
Income taxes	Various		-		14,979		-			14,979		16,766
Gain on property sales			-		-		-			-		(643	)
Depreciation-customer advances	2011		2,363		-		268	(2)		2,631		4,203
Renewable energy programs	2011		2,916		-		-			2,916		-
Total regulatory liabilities		$	160,485	$	14,979	$	268		$	175,732	$	161,817

(1)	Earning a Return includes either a carrying charge on the asset/liability balance, or a return as a component of weighted cost of capital.
(2)	Pending regulatory treatment includes either amounts which have prior regulatory precedent or have been approved and are subject to prudency review.
(3)	Assets which are allowed to earn a carrying charge until included in rates.  Reference Note 1, Summary of Significant Accounting Policies, Equity Carrying Charges.
(4)	Represents the asset associated with the difference between revenue recognized in accordance with NPC’s 2008 GRC PUCN authorized rate increase effective July 1, 2009 and the amounts authorized to be billed to customers for the period July 1, 2009 through December 31, 2009.  In its June 2009 order, the PUCN delayed billings to customers during this period in order to mitigate the rate impact during the hottest summer months.  NPC was ordered to track the delayed billings with a carrying charge and seek regulatory approval in a future rate case to determine an appropriate collection period for the delayed billings. Reference further discussion of NPC’s 2008 GRC discussed later.

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Pending Regulatory Actions

   Nevada Power Company and Sierra Pacific Power Company

      Ely Energy Center

On February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade.  The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $78.8 million as of December 31, 2009.  Management expects full recovery of the amounts expended through December 31, 2009.  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.

   Sierra Pacific Power Company

       SPPC California Divestiture Filing

 In October 2009, SPPC and CalPeco filed an application with the CPUC requesting approval of the transaction in which SPPC has agreed to sell its California electric distribution and generation assets to CalPeco.  Upon closing of the transaction, SPPC will transfer to CalPeco all of its California electric distribution and generation assets and approximately 46,000 retail electric customers.  Separately in December 2009, SPPC filed an application with the PUCN requesting PUCN approval of the transaction.  On or before July 1, 2010 SPPC will file certain components of the transaction under its IRP process and request consolidation with the previously filed application.  See Note 16, Assets Held for Sale.

Settled Regulatory Actions

   Nevada Power Company

NPC 2009 DEAA

In February 2009, NPC filed an application to create a new DEAA rate.  In this application, NPC requested to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs.  In September 2009, the PUCN ordered that the DEAA rate remain set at $0.00 per kWh, a slight increase to the Temporary Renewable Energy Development charge and slight decrease to the Renewable Energy Program Rate which is a decrease to revenues of $4.6 million, or a 0.20% decrease.  The PUCN found that NPC’s purchases of fuel and power were prudent and approved those costs for the test period which will be included as an offset to 2009 deferred energy over-collections within the February 2010 DEAA filing.

      NPC 2008 GRC

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

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

• Increase in general rates by $222.7 million, approximately a 9.8% increase;

• ROE and ROR of 10.5% and 8.53%, respectively;

• Authorized to recover the costs of major plant additions including the purchase of the Higgins Generating Station, construction of Clark Peaking Units, an upgrade to the emission control systems on existing units at the Clark Generating Station,  installation of environmental equipment upgrades at the Reid Gardner Generating Station and new transmission and distribution projects;

• CWIP as of November 2008 in rate base for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen Generating Station site; and

• A two part implementation of the rate increase to be billed to customers.  The part I rate increase was effective July 1, 2009 and resulted in a 3% increase to all core customer classes.  The part II rate increase was effective January 1, 2010 and implemented the remainder of the increase to all core customer classes.  The PUCN granted approval for NPC to track and record the difference between the 9.8% general rate increase and billings associated with the part I rate increase each month  in a regulatory asset account and permitted NPC to record a carrying charge on these amounts.  Reference Equity Carrying Charges in Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements for further discussion on the recognition of the carrying charge. NPC will seek authority to amortize this regulatory asset over an appropriate collection period in its next GRC filing, currently scheduled for June 2011.

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NPC 2008 DEAA and BTER Update

In February 2008, NPC filed applications to create a new DEAA rate and to update the going forward BTER.  In these applications, NPC requested to decrease rates by $116.3 million, a decrease of 5.04% while recovering $36 million of deferred fuel and purchased power costs.  The going forward BTER became effective April 1, 2008.  The PUCN issued its order in September 2008 setting the DEAA rate for all customers at $0.00 per kWh effective October 1, 2008.  The PUCN found that NPC’s purchases of fuel and power were prudent and approved those costs for the test period.

NPC 2007 Quarterly BTER Filings

In November 2007, NPC filed an application to update the going forward BTER.  NPC requested to decrease rates by $26.6 million, resulting in a 1% decrease.  The PUCN approved the requested rate change with rates effective January 1, 2008.

In August 2007, NPC filed an application to update the going forward BTER.  NPC requested to increase rates by $22.7 million, resulting in a 1% increase.  The PUCN approved the requested rate change with rates effective October 1, 2007.

NPC 2007 DEAA and BTER Update

In January 2007, NPC filed an application to create a new DEAA rate and to update the going forward BTER.  NPC requested to decrease rates by $33.2 million, while recovering $75 million of deferred fuel and purchased power costs.

In March 2007, NPC filed an update to its going forward BTER which lowered the overall decrease in rates from $33.2 million to $5.9 million, resulting in less than a 1% decrease.  NPC requested the amortization to begin June 1, 2007 and to continue for a 14-month period.

In June 2007, the PUCN approved a stipulation between the parties that resolved all the issues in this case with no material impact to the requested rate change with rates effective June 1, 2007.

NPC 2007 Western Energy Crisis Rate Case

In January 2007, NPC filed an application to recover $83.6 million in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the Western Energy Crisis.  This application requested to begin amortizing the costs over a four-year period beginning June 1, 2007.

In March 2007, the PUCN approved a negotiated settlement where NPC is authorized to recover the $83.6 million plus carrying charges over a three-year period beginning June 1, 2007, which differed from the four-year period requested in the application.

NPC 2001 DEAA

In November 2001, NPC made a deferred energy filing with the PUCN seeking repayment for purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as required by law.  The application sought to establish a rate to repay purchased fuel and power costs of $922 million and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.

In March 2002, the PUCN issued its Order on the application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002.  The Order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs.  NPC and the BCP both sought individual review of the PUCN Order in the First District Court of Nevada (the District Court).  The District Court affirmed the PUCN’s decision.  Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.

In July 2006, the Supreme Court of Nevada issued a ruling reversing $178.8 million of the PUCN’s disallowance which was part of the NPC’s 2001 Deferred Energy Case.  The decision directed the District Court to remand the matter back to the PUCN to determine the appropriate rate schedule.

In March 2007, the PUCN approved a stipulation that authorizes NPC to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges.  The $189.9 million represents Nevada’s jurisdictional portion of the

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$178.8 million disallowance plus carrying charges of $11.1 million from the date the costs were incurred to the date of disallowance by the PUCN.

      NPC 2006 GRC

In November 2006, NPC filed its statutorily required electric GRC and further updated the filing in February 2007.  The filing requested an ROE and ROR of 11.4% and 9.39% and an increase to general revenues of $156.4 million.

The PUCN issued its order in May 2007, with rates effective as of June 1, 2007.  The PUCN order resulted in the following significant items:

• increase in general rates of $120.1 million, a 5.66% increase;

• ROE and ROR of 10.7% and 9.06%, respectively;

• authorized 100% recovery of  unamortized 1999 NPC / SPPC merger costs;

• authorized incentive rate making for the Lenzie Generating Station;

• authorized recovery of accumulated cost and savings, including the net book value of the Mohave Generating Station over an eight year period, see below for further discussion of the Mohave Generating Station.

Mohave Generating Station

NPC owns approximately 14% of the Mohave Generating Station.  Southern California Edison is the operating partner of the Mohave Generating Station.

When operating, the Mohave Generating Station obtained all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes).  This coal was delivered from the mine to the Mohave Generating Station by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generating Station, alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates.  An additional plaintiff, National Parks and Conservation Association, later joined the suit.  In 1999, the plant owners and plaintiffs filed a settlement with the court, which resulted in a consent decree, approved by the court in November 1999.  The consent decree established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter.  Pursuant to the decree, the Mohave Generating Station Units 1 and 2 ceased operations as of January 2006 as the new emission limits were not met.  Due to the lack of resolution regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the Consent Decree.

In December 2005, the Owners of the Mohave Generating Station suspended operation, pending resolution of these issues.  However, in June 2006, majority stake holder Southern California Edison announced it would no longer participate in the efforts to return the plant to service.  As a result, NPC decided it is not economically feasible to continue its participation in the project.  In September 2006, Salt River’s co-tenancy agreement expired and the operating agreement between the Owners expired in July 2006.  The Owners are negotiating an extension of both agreements including a process that addresses how Owners may sell or assign their right, title, interest and obligations in the Mohave Generating Station.

Included in other regulatory assets is approximately $14.5 million, which has been approved by the PUCN and included in rates.  All other costs for Mohave Generating Station, including decommissioning costs continue to be accumulated in other regulatory assets as incurred and will be requested for recovery in future GRC’s, see the Other Regulatory Assets/Liabilities table above .

In June 2009, Southern California Edison announced that the Mohave Generating Station will be dismantled and its operating permits terminated following a December 2005 suspension of operations due to pending environmental matters.  NPC believes it will continue to recover the costs for the Mohave Generating Station through the regulatory process and does not expect the dismantling of the plant to have a material impact on its financial condition.

   Sierra Pacific Power Company

SPPC California GRC

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

• Increase in general rates of $5.5 million, approximately an 8% increase;

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 • ROE and ROR of 10.7% and 8.51%, respectively;

• Approval of authorization to recover the costs of major plant additions, which include the Tracy Generating Station, and distribution plant additions, as well as a decrease to the California Energy Efficiency Program; and

• Approval of a two-part mechanism to recover changes in non-energy cost adjustment clause costs incurred during the two years between rate cases.

The CPUC approved the settlement and rates were effective December 1, 2009.

SPPC 2009 Nevada Gas DEAA

In February 2009, SPPC filed an application to create a new gas DEAA rate for Nevada customers.  In this application, SPPC requested to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs.  The PUCN issued its order in September 2009 approving SPPC’s requested rate decrease and approving SPPC’s purchases of natural gas and propane as prudent for the test period.  The new DEAA rate became effective October 1, 2009.

       SPPC 2009 Nevada Electric DEAA

In February 2009, SPPC filed an application to create a new electric DEAA rate for Nevada customers.  In this application, SPPC requested to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs.  The PUCN issued its order in September 2009 decreasing rates by $30.8 million, a decrease of 3.19% and approving SPPC’s purchases of fuel and power as prudent for the test period.  The new credit DEAA rate became effective October 1, 2009.

SPPC Nevada Gas DEAA and BTER Update

In December 2007, SPPC filed for the authority to implement quarterly BTER adjustments for its natural gas and liquefied propane gas services.  The authority was approved in January 2008, and as a result, inFebruary 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER.  In these applications SPPC requested to decrease rates by $9.9 million, a decrease of 5.53%, while refunding an over collection of $11.4 million in deferred natural gas and liquid propane costs.  The going forward BTER became effective April 1, 2008.  The PUCN issued its order in October 2008 setting the DEAA rate at $0.00 per therm effective October 1, 2008 and approving SPPC’s purchases of natural gas and propane for the test period as prudent.

SPPC Nevada Electric DEAA and BTER Update

In February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER.  In these applications SPPC requested to decrease rates by $42.1 million, a decrease of 4.57%, while refunding an over collection of $20.9 million in deferred fuel and purchased power costs.  The going forward BTER became effective April 1, 2008.  The PUCN issued its order in October 2008 setting the DEAA rate at $0.00 per kWh effective October 1, 2008.  The PUCN found that SPPC’s purchases of fuel and power were prudent and approved those costs for the test period.

SPPC California Energy Cost Adjustment Clause

In April 2008, SPPC filed to decrease rates by $12.2 million, a decrease of 15.2%.  The CPUC approved the filing in August 2008.  The rates requested in this filing were effective September 1, 2008.

      SPPC 2007 Nevada GRC

In December 2007, SPPC filed its statutorily required electric GRC.  The filing requested a ROE and ROR of 11.5% and 8.73%, respectively, and an increase to general revenues of $110.8 million.

The PUCN issued its order in June 2008, with rates effective July 1, 2008.  The PUCN order resulted in the following significant items:

• Increase in general rates of $87.1 million, a 10.45% increase;

• ROE and ROR of 10.6% and 8.41%, respectively;

• Authorization to recover the costs of the new 541 MW (nominally rated) Tracy Generating Station; and

• Authorization to recover the projected operating and maintenance costs associated with the new Tracy Generating Station.

SPPC Piñon Pine

In its 2003 GRC, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”).  The Project represented experimental technology tested pursuant to a DOE Clean Coal

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Technology initiative.  Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project.  SPPC's participation in the Project had received PUCN approval as part of SPPC’s 1993 IRP.  While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational.  After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable. 

In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project.  As a result, these amounts were expensed in 2004.  SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434).  On January 25, 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (“the Order”).  On March 27, 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court.  On June 12, 2006, the District Court granted the PUCN’s motion to stay the Order.  The Supreme Court dismissed the appeal in September 2006.  Requests for rehearing were denied in late December 2006, and on January 18, 2007 the matter was remitted back to the District Court, which, consistent with the Order, remanded the matter back to the PUCN for further review.

On March 18, 2008, the PUCN issued an order to place $5.8 million (Nevada jurisdiction) of the previously disallowed $43 million unreimbursed costs in a regulatory asset account without a carrying charge.  As a result of this order and in accordance with FASC accounting for regulated operations and abandonments, SPPC recognized approximately $4.3 million in income for the year ended December 31, 2008.  The remaining difference of $1.5 million will be recognized over an approximate six year period.  The time for any party to appeal the PUCN’s decision ended in June 2008 and no appeals were filed.

      SPPC 2007 Quarterly Electric BTER Filings

In November 2007, SPPC filed an application to update the going forward BTER.  SPPC requested to decrease rates by $7.7 million, resulting in approximately a 1% decrease.  The PUCN approved the requested rate change with rates effective January 1, 2008.

In August 2007, SPPC filed an application to update the going forward BTER.  SPPC requested to decrease rates by $17.4 million, resulting in a 1.85% decrease.  The PUCN approved the requested rate change with rates effective October 1, 2007.

SPPC 2007 Nevada Natural Gas and Propane DEAA and BTER Update

In May 2007, SPPC filed an application to create a new Deferred Energy Accounting Adjustment (DEAA) rate and to update the going forward BTER.  SPPC requests to increase rates by $13.4 million, while recovering $900 thousand of deferred gas costs.  This application requests an overall rate increase of 7.05%.

Subsequent to the filing, SPPC reduced its deferred gas costs by $2.3 million due to a re-allocation of cost between the gas and electric segments.  As a result, SPPC updated its filing from recovering $900 thousand of deferred gas costs to a refund of $1.4 million to the customers.  In addition, due to lower natural gas costs, SPPC updated its forecasts used in calculating the going forward BTER and its overall requested rate change went from an increase of $13.4 million to a decrease of $2.3 million.

In November 2007, the PUCN approved the revised rate change with rates effective December 1, 2007.

SPPC 2006 Nevada Western Energy Crisis Rate Case

In December 2006, SPPC filed an application to recover $22.6 million in deferred legal and settlement costs incurred to resolve claims arising from the Western Energy Crisis.  This application requested an overall rate increase of 0.53% and to begin amortizing the costs over a four-year period beginning July 1, 2007.

In February 2007, SPPC entered into a stipulation pursuant to which SPPC replaced its request to implement rates on July 1, 2007 with a request to recover approximately $16.3 and $6.3 million, respectively, in deferred settlement and legal costs.  SPPC further requested authority to recover carrying charges on the regulatory asset.

In November 2007, the PUCN authorized SPPC to establish a regulatory asset, including carrying charges, to recover $2.8 million of the legal costs.  The recovery period was not established in this proceeding but will be determined in a later filing.  As a result of this order and recognition of legal reserves and other adjustments in prior periods, SPPC recorded a $7.6 million expense (net of taxes) in the fourth quarter of 2007.

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SPPC 2006 Nevada Electric DEAA and BTER Update

In December 2006, SPPC filed an application to create a new electric DEAA rate and to update the electric BTER.  SPPC requested to decrease rates by $7.9 million, a decrease of 0.86%, while recovering $18.7 million of deferred fuel and purchased power costs.  SPPC sought recovery using a symmetrical two-year amortization period beginning July 1, 2007.

In June 2007, the PUCN approved a stipulation between the parties that resolved all the issues in this case with no material impact to the requested rate change with rates effective July 1, 2007.

FERC Matters

   California Wholesale Spot Market Refunds

NPC and SPPC are participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001.  Both of the Utilities made spot market sales that are eligible for mitigation, therefore the Utilities expect to pay refunds resulting from the recalculated energy prices.  Parties have contested the FERC’s decision to limit the timeframe for the recalculations and a Ninth Circuit court decision remanded a related issue to the FERC, therefore NPC and SPPC are not able to determine the eventual magnitude of refunds that may result from this FERC process.  NPC and SPPC are actively participating in this docket to ensure their interests are represented.

   Nevada Power Company

Based on the FERC’s orders to date, NPC believes the recalculated energy prices for NPC sales to the California Independent System Operator (CAISO) and the bankrupt California Power Exchange (CALPX) would result in an approximate $19 million refund.  The FERC has also allowed for energy sellers to provide cost justification in the event the recalculated energy prices fall below sellers’ costs.  NPC developed and filed a cost based filing, which justified a $6 million reduction to the estimated refunds resulting in a $13 million refund.

CAISO and CALPX currently owe NPC approximately $19 million for power delivered during the same timeframe for which NPC had fully reserved for in 2001.  As such, if NPC is ordered to pay CAISO and CALPX the refunds discussed above, NPC would apply such payments towards NPC’s receivable of $19 million from CAISO and CALPX.

   Sierra Pacific Power Company

Based on the FERC’s orders to date, SPPC believes the recalculated energy prices for sales to the CAISO and CALPX during the October 2, 2000 to June 20, 2001 timeframe would result in a $4 million refund.

CAISO and CALPX currently owe SPPC approximately $1 million for power delivered during the same timeframe and SPPC recorded a reserve against the $1 million receivable in 2001.  In 2004, SPPC recorded an additional $3 million liability for this item.

NOTE 4.                      INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

Investments in subsidiaries and other property consisted of (dollars in thousands):

NV Energy, Inc.

	December 31,
	2009		2008
Investments held in Rabbi Trust (1)	$	26,490	$	-
Cash Value-Life Insurance		2,512		2,456
Non-utility property of NEICO		5,338		5,238
Non-utility property of SPC (2)		4,130		4,130
Property not designated for Utility use		12,255		12,418
Other non-utility Property		444		947
	$	51,169	$	25,189

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Nevada Power Company

	December 31,
	2009		2008
Investments held in Rabbi Trust(1)	$	21,492	$	-
Cash Value-Life Insurance		2,512		2,456
Non-utility property of NEICO		5,338		5,238
Property not designated for Utility use		11,825		12,007
	$	41,167	$	19,701

Sierra Pacific Power Company

	December 31,
	2009		2008
Investments held in Rabbi Trust(1)	$	4,998	$	-
Property not designated for Utility use		430		403
	$	5,428	$	403

(1)	Rabbi trust assets represent non-qualified deferred compensation plans, which consist of actively traded money market and equity funds with quoted prices in active markets which are considered level 1 in the fair value hierarchy. The balance also includes life insurance policies, which are recorded at its cash surrender value of $4.6 million on the consolidated balance sheet.
(2)	SPC, a wholly owned subsidiary of NVE, incurred an impairment charge of its long haul network assets of $5.9 million, before taxes in 2008.

NOTE 5.                       JOINTLY OWNED FACILITIES

	% Owned			Plant In Service		Accumulated Depreciation		Net Plant in Service		CWIP
NPC
Navajo Generating Station		11.3	%	$	249,193	$	135,732	$	113,461	$	341
Reid Gardner Generating Station  No. 4		32.2	%	$	174,671	$	103,961	$	70,710	$	16,368
Silverhawk Generating Station		75.0	%	$	246,098	$	39,715	$	206,383	$	2
				$	669,962	$	279,408	$	390,554	$	16,711
SPPC
Valmy Generating Station		50.0	%	$	304,131	$	195,479	$	108,652	$	3,023

The amounts for Navajo Generating Station include NPC’s share of transmission systems, general plant equipment and NPC’s share of the jointly owner railroad which delivers coal to the plant.  Each participant provides its own financing for all these jointly owned facilities.  NPC’s share of the operating expenses for these facilities is included in the corresponding operating expenses in its consolidated statement of income.

Reid Gardner Generating Station Unit No. 4 is owned by the California Department of Water Resources (67.8%) and NPC (32.2%).  NPC is operating agent.  Contractually, NPC is entitled to receive 25 MW of base load capacity and 232 MW of peaking capacity.  Operationally, Unit No. 4 subject to heat input at 257 MW is entitled to use 100% of the unit’s peaking capacity for 1500 hours each year and is entitled to 9.6% of the first 250 MW of capacity and associated energy.  The contract expires in 2013.  NPC's share of the operating expenses for this facility is included in the corresponding operating expenses in its consolidated income statements.

NPC is the operator of the Silverhawk Generating Station, which is jointly owned with SNWA.  NPC’s owns 75% and its share of direct operation and maintenance expenses is included in its accompanying consolidated income statements.

SPPC and Idaho Power Company each own a 50% undivided interest in the Valmy Generating Station, with each company being responsible for financing its share of capital and operating costs.  SPPC is the operating of the plant for both parties.  SPPC’s share of direct operation and maintenance expenses for Valmy Generating Station are in included in its accompanying consolidated income statements.

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NOTE 6.                      LONG-TERM DEBT

NVE’s, NPC’s and SPPC’s long term debt consists of the following (dollars in thousands):

	December 31, 2009											December 31, 2008
Long-Term Debt:	SPPC			NPC			NVE Holding Co.		Consolidated			SPPC			NPC			NVE Holding Co.		Consolidated
Secured Debt
Debt Secured by General and Refunding Mortgage Securities
8.25%   NPC Series A due 2011	$	-		$	350,000		$	-	$	350,000		$	-		$	350,000		$	-	$	350,000
6.50%   NPC Series I due 2012		-			130,000			-		130,000			-			130,000			-		130,000
5.875% NPC Series L due 2015		-			250,000			-		250,000			-			250,000			-		250,000
5.95%   NPC Series M due 2016		-			210,000			-		210,000			-			210,000			-		210,000
6.65%   NPC Series N due 2036		-			370,000			-		370,000			-			370,000			-		370,000
6.50%   NPC Series O due 2018		-			325,000			-		325,000			-			325,000			-		325,000
6.75%   NPC Series R due 2037		-			350,000			-		350,000			-			350,000			-		350,000
6.50%   NPC Series S due 2018		-			500,000			-		500,000			-			500,000			-		500,000
7.375% Series U due 2014		-			125,000			-		125,000			-			-			-		-
7.125% Series V due 2019		-			500,000			-		500,000			-			-			-		-
6.25% SPPC Series H due 2012		100,000			-			-		100,000			100,000			-			-		100,000
6.00% SPPC Series M due 2016		450,000			-			-		450,000			300,000			-			-		300,000
6.75% SPPC Series P due 2037		251,742			-			-		251,742			325,000			-			-		325,000
5.45% SPPC Series Q due 2013		250,000			-			-		250,000			250,000			-			-		250,000
Variable Rate Notes
NPC IDRB Series 2000A due 2020		-			98,100			-		98,100			-			100,000			-		100,000
NPC PCRB Series 2006 due 2036		-			37,700			-		37,700			-			39,500			-		39,500
NPC PCRB Series 2006A due 2032		-			37,975			-		37,975			-			40,000			-		40,000
SPPC PCRB Series 2006A due 2031		58,200			-			-		58,200			58,700			-			-		58,700
SPPC PCRB Series 2006B due 2036		75,000			-			-		75,000			75,000			-			-		75,000
SPPC PCRB Series 2006C due 2036		81,475			-			-		81,475			84,800			-			-		84,800
SPPC WFRB Series 2007A due 2036		-			-			-		-			40,000			-			-		40,000
Revolving Credit Facilities		15,000			110,000			-		125,000			152,912			409,629			-		562,541
Unsecured Debt
Revenue Bonds
5.30% NPC Series 1995D due 2011		-			14,000			-		14,000			-			14,000			-		14,000
5.45% NPC Series 1995D due 2023		-			6,300			-		6,300			-			6,300			-		6,300
5.50% NPC Series 1995C due 2030		-			44,000			-		44,000			-			44,000			-		44,000
5.60% NPC Series 1995A due 2030		-			76,750			-		76,750			-			76,750			-		76,750
5.90% NPC Series 1995B due 2030		-			85,000			-		85,000			-			85,000			-		85,000
5.90% NPC Series 1997A due 2032		-			-			-		-			-			52,285			-		52,285
7.803% NVE Senior Notes due 2012		-			-			63,670		63,670			-			-			63,670		63,670
8.625% NVE Notes due 2014		-			-			230,039		230,039			-			-			230,039		230,039
6.75% NVE Senior Notes due 2017		-			-			191,500		191,500			-			-			191,500		191,500
Obligations under capital leases		-			47,047			-		47,047			-			54,265			-		54,265
Unamortized bond premium and discount, net		15,808			(11,958	)		483		4,333			9,575			(12,932	)		680		(2,677	)
Current maturities and sinking fund requirements		(15,000	)		(119,474	)		-		(134,474	)		(600	)		(8,691	)		-		(9,291	)
Other, excluding current portion		-			-			-		-			600			-			-		600
Total Long-Term Debt	$	1,282,225		$	3,535,440		$	485,692	$	5,303,357		$	1,395,987		$	3,385,106		$	485,889	$	5,266,982

   Maturities of Long-Term Debt

As of December 31, 2009, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

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	SPPC		NPC			NVE Holding Co.		NVE Consolidated
2010(1)	$	15,000	$	118,004		$	-	$	133,004
2011		-		369,924			-		369,924
2012		100,000		136,449			63,670		300,119
2013		250,000		7,146			-		257,146
2014		-		129,236			230,039		359,275
		365,000		760,759			293,709		1,419,468
Thereafter		916,417		2,906,113			191,500		4,014,030
		1,281,417		3,666,872			485,209		5,433,498
Unamortized Premium(Discount) Amount		15,808		(11,958	)		483		4,333
Total	$	1,297,225	$	3,654,914		$	485,692	$	5,437,831

(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 bonds are issued.

   Lease Commitments

In 1984, NPC entered into a 30-year capital lease for its Pearson building with five-year renewal options beginning in year 2015.  The fixed rental obligation for the first 30 years is $5.1 million per year.  Also, NPC has a power purchase contract with Nevada Sun-Peak Limited Partnership.  The contract contains a buyout provision for the facility at the end of the contract term in 2016.  The facility is situated on NPC property.  In 2007, NPC entered into a 20-year lease, with three 10 year renewal options, to occupy land and building for its Beltway Complex, an operations center in southern Nevada.  As required by the Leases Topic of the FASC, NPC accounts for the building portion of the lease as a capital lease and the land portion of the lease as an operating lease.   NPC transferred operations to the facilities in June 2009.  In 2007, the Utilities entered into Master leasing agreements of which various pieces of equipment qualify as capital leases.  The remaining equipment is treated as operating leases.  The lease term is for 7 years.

Future cash payments for these capital leases, combined, as of December 31, 2009, were as follows (dollars in thousands):

2010	$	12,466
2011		9,630
2012		9,493
2013		9,510
2014		5,723
Thereafter		26,945
Total Minimum Lease Payments	$	73,767
Less amounts representing interest	$	26,716
Present Value of Net minimum lease payments	$	47,051

   Financing Transactions

NPC

         Redemption of Clark County, Nevada Industrial Development Revenue Bonds, Series 1997A

In November 2009, NPC provided a notice of redemption to the holders of all of the approximately $52.3 million aggregate principal amount of Clark County, Nevada Industrial Development Revenue Bonds, Series 1997A.  The notes were redeemed in December 2009, at 100% of the stated principal amount plus accrued interest to the date of redemption.  NPC redeemed these notes with the use of its revolving credit facility.

Maturity of Clark County Nevada Pollution Control Revenue Bonds, Series 2000B

In October 2009 the Clark County Nevada Pollution Control Revenue Bonds, Series 2000B, in the aggregate principal amount of $15 million, matured.  In July 2008, these securities were converted from auction rate securities to variable rate demand notes.   NPC purchased 100% of the bonds at that time, and remained the sole holder of these bonds until the maturity date.   NPC financed the maturity with available cash.

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         General and Refunding Mortgage Notes, Series V

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

         General and Refunding Mortgage Notes, Series U

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

          General and Refunding Mortgage Notes, Series S

In July 2008, NPC issued and sold $500 million of its 6.5% General and Refunding Mortgage Notes, Series S, due 2018.  The net proceeds of the issuance were used to repay $270million of amounts outstanding under NPC’s revolving credit facility and for general corporate purposes.

In August 2008, NPC redeemed approximately $17.2 million 9.00% General and Refunding Mortgage Notes, Series G, at 104.50% of the stated principal amount, plus accrued interest to the date of redemption.  NPC used available cash on hand to redeem these notes.

         Conversion of Coconino County Pollution Control Refunding Revenue Bonds and Clark County Pollution Control Revenue Bonds

In July 2008, NPC converted the $13 million principal amount Coconino County, Arizona Pollution Control Refunding Revenue Bonds Series 2006B bonds, due 2039 and the $15 million principal amount Clark County Nevada Pollution Control Revenue Bonds, Series 2000B due 2009, (collectively, the “Bonds”) from auction rate securities to variable rate demand notes.  The purpose of these conversions was to reduce interest costs and volatility associated with these Bonds.  NPC purchased 100% of the Bonds with the use of its revolving credit facility and available cash, and is the sole holder of the Bonds until such time as NPC determines to reoffer the Pollution Control Bonds to investors.  The Bonds remain outstanding and have not been retired or cancelled.  However, as NPC is the sole holder of the Bonds, for financial reporting purposes the investment in the Bonds and the indebtedness is offset for presentation purposes.

         Revolving Credit Facilities

In April 2006, NPC increased the size of its revolving credit facility from $350 million to $600 million.  The facility provides additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures.  In March 2009, NPC amended its $600 million Second Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility.  This amendment reduced the capacity of the facility to approximately $589 million.  In January 2009, NPC entered into a new $90 million supplemental revolving credit facility.  The supplemental facility expired on January 3, 2010.  Currently, NPC is assessing its options with respect to replacing its expired and expiring credit facilities.  

As of December 31, 2009, NPC had $15.8 million of letters of credit outstanding and had $110 million in borrowings outstanding under the $600 million revolving credit facility, which expires in November 2010.  As of February 19, 2010, NPC had $14.8million of letters of credit outstanding and had $145 million borrowed under the $600 million revolving credit facility.

The NPC Credit Agreements contain two financial maintenance covenants.  The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.  As of December 31, 2009, NPC was in compliance with these covenants.

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

The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.  These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.

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      Sierra Pacific Power Company

         Tender Offer for General and Refunding Mortgage Notes, Series P

In November 2009, SPPC provided notice of a cash tender offer to purchase up to $75 million aggregate principal amount of its 6.75% General and Refunding Mortgage Notes, Series P, due 2037.  Those holders who tendered their Bonds by the early tender date of December 7, 2009 received a purchase price of $1,102.15 per $1,000 principal amount of Notes.  Holders who validly tendered their Notes after the early tender date but before the tender expiration date of December 21, 2009 received a purchase price of $1,062.15 per $1,000 principal amount of Notes.  In addition, holders received accrued and unpaid interest to, but not including the date of purchase.  Approximately $73.3 million of the $325 million Series P Notes outstanding were validly tendered and accepted by SPPC.  The tender offer was funded predominantly with cash on hand, with the balance being funded with borrowings under its revolving credit facility.

         General and Refunding Mortgage Notes, Series M

On August 21, 2009, SPPC issued an additional $150 million in aggregate principal amount of its 6% General and Refunding Mortgage Notes, Series M, as part of the same series as the original Series M Notes issued in March 2006.  Upon the issuance of these Notes, the aggregate principal amount of the Series M Notes outstanding is $450 million.  The proceeds from the second issuance were used to repay amounts outstanding under SPPC’s revolving credit facility.

         General and Refunding Mortgage Notes, Series Q

In September 2008, SPPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013.  The net proceeds of the issuance were used to repay $238million of amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Conversions

            Conversion of Washoe County Water Facilities Refunding Revenue Bonds

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

               Conversion of Humboldt County Pollution Control Refunding Revenue Bonds Series 2006

In October 2008, SPPC converted the $49.8 million principal amount, Humboldt County, Nevada Pollution Control Refunding Revenue Bonds Series 2006 bonds, due 2029 (the “Pollution Control Bonds”) from auction rate securities to variable rate demand notes.  The purpose of the conversion was to reduce interest costs and volatility associated with these bonds.  SPPC purchased 100% of the Pollution Control Bonds on that date, with the use of its revolving credit facility and available cash, and are the sole holder of the Pollution Control Bonds until such time as SPPC determines to reoffer the Pollution Control Bonds to investors.  The Pollution Control Bonds remain outstanding and have not been retired or cancelled.  However, as SPPC is the sole holder of the Pollution Control Bonds, for financial reporting purposes the investment in the Pollution Control Bonds and the indebtedness is offset for presentation purposes.

                Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In July 2008, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007B bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes.  The purpose of the conversion was to reduce interest costs and volatility associated with these bonds.  SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Water Bonds to investors.  These Water Bonds remain outstanding and have not been retired or cancelled.  However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness is offset for presentation purposes.

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         Revolving Credit Facility

In April 2006, SPPC increased the size of its revolving credit facility from $250 million to $350 million.  The facility provides additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures.  On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, due November 2010, to remove a bankrupt lending bank from the facility.  This amendment reduced the capacity of the facility to approximately $332 million.  SPPC’s credit facility expires in November 2010.  Currently, SPPC is assessing its options with respect to replacing its expiring credit facility.

As of December 31, 2009, SPPC had $15.6 million of letters of credit outstanding and had $15 million borrowed under the revolving credit facility.  As of February 19, 2010, SPPC had $16.2million of letters of credit and had $25 million borrowed under the revolving credit facility.

The SPPC Credit Agreement contains two financial maintenance covenants.  The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.  As of December 31, 2009, SPPC was in compliance with these covenants.

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

The SPPC Credit Agreement, similar to SPPC's Series H Notes, places certain restrictions on debt incurrence, liens and dividends.  These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.

      NVE

         Debt Repurchase

In the fourth quarter of 2008, NVE repurchased approximately $20 million of the 8.625% Senior Notes and approximately $19 million of the 6.75% Senior Notes.  NVE used cash on hand to pay the total consideration of approximately $34.7 million, including accrued interest.  As of December 31, 2009, the outstanding balances for the 6.75% Senior Notes and 8.625% Senior Notes were $191.5 million and $230 million, respectively.

NOTE 7.                      FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2009, carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments.

The total fair value of NVE’s consolidated long-term debt at December 31, 2009, is estimated to be $5.6 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $4.9 billion as of December 31, 2008.

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

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

NOTE 8.                      DEBT COVENANT AND OTHER RESTRICTIONS

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.  In 2009, NPC and SPPC paid $112 million and $128.8 million in dividends, respectively, to NVE.  

On February 2, 2010, NPC and SPPC declared a $27 million and $13 million dividend, respectively, to NVE, to be paid in February 2010.

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Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise may impact the amount of dividends that the Utilities may declare and pay.

Certain debt agreements entered into by NVE and the Utilities contain covenants which set restrictions on certain payments, including the amount of dividends they may declare and pay, and restrict the circumstances under which such dividends may be declared and paid.

Limits on Restricted Payments

   NVE

Dividends are considered periodically by NVE’s BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, NVE’s financial conditions and other matters within the discretion of the BOD, as well as dividend restrictions set forth in NVE’s debt.  The BOD will continue to review the factors described above on a periodic basis to determine if and when it is prudent to declare a dividend on NVE’s Common Stock.  There is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid at the same amount or with the same frequency as in the past.  In February, June and September 2009, NVE paid a cash dividend of $0.10 per share.  In October 2009, the BOD increased the cash dividend to $0.11 per share, which was paid in December 2009.  In February 2010, NVE declared a cash dividend of $0.11 per share for common stock holders of record as of March 2, 2010.

Certain NVE debt agreements contain covenants that limit the amount of restricted payments, including dividends that may be made by NVE.  However, as of December 31, 2009, NVE complied with all such covenants, and management does not believe that these covenants will materially affect NVE’s ability to pay dividends.

      Dividend Restrictions Applicable to the Utilities

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

Ability to Issue Debt

   NVE

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 December 31, 2009, NVE (consolidated) would be allowed to incur up to $1.2 billion of additional consolidated indebtedness, assuming an interest rate of 7%.  The amount of additional consolidated indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.

Notwithstanding this restriction, under the terms of the debt, NPC and SPPC would still be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.  As of December 31, 2009, the combined total outstanding indebtedness and letters of credit under their respective revolving credit facilities was approximately $156.4 million.

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

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   NPC

      Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt.  As of December 31, 2009, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $750 million in long term debt, in addition to the use of its existing credit facilities.  However, depending on NVE’s or SPPC’s issuance of long term debt or the use of the Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor.  The factors affecting NPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of December 31, 2009, NPC has remaining financing authority from the PUCN to issue (1) long term debt of up to $750 million for the period ending December 31, 2010, (2) ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and (3) authority to refinance up to approximately $471 million of long-term debt securities.
b.	Financial covenants within NPC’s financing agreements – NPC’s $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005 contains two financial maintenance covenants.  The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less that 2.0 to 1.  As of December 31, 2009, NPC was in compliance with these covenants. In order to maintain compliance with these covenants, NPC is limited to $2.0 billion of additional indebtedness.
	All other financial covenants contained in NPC’s revolving credit facility and its financing agreements are suspended, as NPC’s senior secured debt is rated investment grade.  However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and
c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.2 billion.

      Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of December 31, 2009, approximately $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $718.7 million of General and Refunding Mortgage Securities as of December 31, 2009.  That amount is determined on the basis of:

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

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

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

   SPPC

      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 December 31, 2009, 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-

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term debt or the use of 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 December 31, 2009, SPPC has remaining financing authority from the PUCN to issue (1) long term debt of up to $350 million for the three-year period ending December 31, 2012, (2) ongoing authority to maintain a revolving credit facility of up to $600 million, and (3) authority to refinance approximately $348 million of long-term debt securities.
b.	Financial covenants within SPPC’s financing agreements – SPPC’s $332 million Amended and Restated Revolving Credit Agreement dated November 2005 contains two financial maintenance covenants.  The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.  The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less that 2.0 to 1.  As of December 31, 2009, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC is limited to $832 million of additional indebtedness.
	All other financial covenants contained in SPPC’s revolving credit facility and its financing agreements are suspended, as SPPC’s senior secured debt is rated investment grade.  However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants; and
c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.2 billion.

     Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of December 31, 2009, approximately $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $572.0 million of General and Refunding Mortgage Securities as of December 31, 2009.  That amount is determined on the basis of:

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

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

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

NOTE 9.                      DERIVATIVES AND HEDGING ACTIVITIES

NVE, SPPC and NPC 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 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 not recorded on the Consolidated Balance Sheets 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

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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 terminate in 2011, for an aggregated notional amount of $350 million associated with its $350 million 8.25% General and Refunding  Mortgage Notes, Series A, due 2011.  These interest rate swaps manage the existing fixed rate interest rate exposure with a variable interest rate in order to lower overall borrowing costs.  As NPC met the requirements of the Regulated Operations Topic of the FASC, as of December 31, 2009, the fair value of the interest rate swaps were recorded as a Risk Management Asset with the corresponding offset recorded as a Risk Management Regulatory Liability and are included in the fair value table below.

Credit Risk Contingent Features

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts.  The contracts require that the Utilities maintain their Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into.  In the event that the Utilities Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of December 31, 2009, the maximum amount of collateral NPC and SPPC would be required to post under these agreements is approximately $39.4 million and $28.8 million, respectively, based on mark-to-market liability values, which are substantially based on quoted market prices.  Of this amount, approximately $30.1 million and $23.2 million, respectively, would be required if NPC and SPPC are downgraded one level and additional amounts of approximately $9.3 million and $5.6 million would be required respectively if NPC and SPPC are downgraded two levels.

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 which are not considered a derivative asset.  Option premiums upon settlement are recorded in fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism.  Option premium amounts included in risk management assets for NVE, NPC and SPPC were as follows (dollars in millions):

	December 31, 2009						December 31, 2008
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	11.9	$	9.2	$	2.7	$	13.3	$	9.7	$	3.6
Non-Current		1.9		1.4		0.5		5.6		4.2		1.4
Total	$	13.8	$	10.6	$	3.2	$	18.9	$	13.9	$	5.0

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

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

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	December 31, 2009									December 31, 2008
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC
Risk management assets- current	$	15.7		$	12.7		$	3.0		$	2.8		$	2.0		$	0.8
Risk management assets- noncurrent(1)		4.8			4.2			0.6			4.4			3.2			1.2
Total risk management assets		20.5			16.9			3.6			7.2			5.2			2.0
Risk management liabilities- current		66.9			39.1			27.8			313.8			222.9			90.9
Risk management liabilities- noncurrent		2.2			1.1			1.1			53.4			35.2			18.2
Total risk management liabilities		69.1			40.2			28.9			367.2			258.1			109.1
Risk management regulatory assets/liabilities – net (2)	$	(48.6	)	$	(23.3	)	$	(25.3	)	$	(360.0	)	$	(252.9	)	$	(107.1	)

(1)

Included in Risk management assets – noncurrent is a $2.6 million cumulative gain for interest rate swaps with the offset recorded in the Risk management regulatory assets/liabilities amounts above.

(2)

When amount is negative it represents a Risk Management Regulatory Asset, when positive it represents a Risk Management Regulatory Liability.  For the year ended December 31, 2009, NVE and the Utilities would have recorded a gain of $311.4 million, $229.6 million, and $81.8 million, respectively; however, as permitted by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains and losses, which are included in the Risk Management Regulatory Assets/Liabilities amounts above.

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate.  The Utilities’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in market prices.  The decrease in risk management liabilities as of December 31, 2009, as compared to December 31, 2008, is primarily due to contract settlements and reduced hedging volume during the year ended December 31, 2009.

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

	December 31, 2009						December 31, 2008
	Commodity Volume (MMBTU)						Commodity Volume (MMBTU)
	NVE		NPC		SPPC		NVE		NPC		SPPC
Commodity volume assets- current		47.1		40.7		6.4		1.2		1.0		0.2
Commodity volume assets- noncurrent		10.3		7.6		2.7		1.1		1.0		0.1
Total commodity volume of assets		57.4		48.3		9.1		2.3		2.0		0.3
Commodity volume liabilities- current		51.7		32.7		19.0		119.9		86.7		33.2
Commodity volume liabilities- noncurrent		7.8		5.3		2.5		40.6		28.6		12.0
Total commodity volume of liabilities		59.5		38.0		21.5		160.5		115.3		45.2

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NOTE 10.                      INCOME TAXES (BENEFITS)

NVE

The following reflects the composition of taxes on income from continuing operations (dollars in thousands):

	2009			2008			2007
Provisions for income taxes
Current and other
Federal	$	(34,072	)	$	44,647		$	10,503
State		12			12			70
Total current and other		(34,060	)		44,659			10,573
Deferred
Federal		114,053			54,341			85,165
State		548			693			366
Total deferred		114,601			55,034			85,531
Amortization of excess deferred taxes		(1,709	)		(1,365	)		(2,226	)
Amortization of investment tax credits		(3,381	)		(2,974	)		(6,323	)
Total provision for income taxes	$	75,451		$	95,354		$	87,555

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):

	2009			2008			2007
Net Income	$	182,936		$	208,887		$	197,295
Total income tax expense		75,451			95,354			87,555
Pretax income		258,387			304,241			284,850
Statutory tax rate		35	%		35	%		35	%
Federal income tax expense at statutory rate		90,435			106,484			99,698
Depreciation related to difference in cost basis for tax purposes		(2,067	)		1,132			2,970
AFUDC - equity		(8,496	)		(13,454	)		(11,133	)
Investment tax credit amortization		(3,381	)		(2,973	)		(6,322	)
Regulatory asset for goodwill		2,742			2,742			2,742
Research and development credit		(1,120	)		(1,310	)		(1,130	)
Other – net		(2,662	)		2,733			730
Provision for income taxes	$	75,451		$	95,354		$	87,555
Effective tax rate		29.2	%		31.3	%		30.7	%

The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):

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	2009			2008
Deferred income tax assets
Net operating loss and credit carryovers	$	208,118		$	34,839
Employee benefit plans		66,292			107,622
Customer advances		27,921			30,851
Gross-ups received on contribution in aid of construction and customer advances		28,119			30,870
Deferred revenues		5,336			5,440
Deferred energy		18,060			-
Reserves		14,376			15,419
Other		33,198			30,473
Subtotal		401,420			255,514
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		9,812			11,521
Unamortized investment tax credit		12,317			13,958
Subtotal		22,129			25,479
Total deferred income tax assets before valuation allowance		423,549			280,993
Valuation allowance		(1,430	)		(1,160	)
Total deferred income tax assets after valuation allowance	$	422,119		$	279,833
Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	881,282		$	530,048
Deferred energy		-			89,182
Regulatory assets		169,128			183,622
Other		95,294			82,687
Subtotal		1,145,704			885,539
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		261,633			264,779
Total deferred income tax liability	$	1,407,337		$	1,150,318
Net deferred income tax liability	$	745,714		$	631,185
Net deferred income tax liability associated with regulatory matters		239,504			239,300
Total net deferred income tax liability	$	985,218		$	870,485

NVE’s balance sheets contain a net regulatory tax asset of $239.5 million at December 31, 2009 and $239.3 million at December 31, 2008.  For balance sheet presentation, the regulatory tax asset is included in regulatory assets.  The regulatory tax asset balance consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE.  Offset against these amounts are future revenues to be refunded to customers (regulatory tax liabilities).  For balance sheet presentation, the regulatory tax liability is included in regulatory liabilities.  The regulatory tax liability balance consists of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits.  The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986.  The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment tax credit.

The following table summarizes NVE’s net regulatory tax asset and liability (dollars in thousands):

	2009		2008
Tax benefits flowed through to customers
Related to property	$	117,212	$	116,167
Related to goodwill		144,421		148,612
Regulatory tax asset		261,633		264,779
Liberalized depreciation at rates in excess of current rates		9,812		11,521
Unamortized investment tax credits		12,317		13,958
Regulatory tax liability		22,129		25,479
Net regulatory tax asset	$	239,504	$	239,300

NVE and its subsidiaries file a consolidated federal income tax return.  Current income taxes are allocated based on NVE’s and each subsidiaries’ respective taxable income or loss and tax credits as if each subsidiary filed a separate return.

The following table summarizes as of December 31, 2009 the net operating loss and tax credit carryovers and associated carryover periods, and  valuation allowance for amounts which NVE has determined that realization is uncertain (dollars in thousands):

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	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Expiration Period
Net operating loss	$	181,434	$	-	$	181,434		2022-2029
Research and development credit		11,241		-		11,241		2022-2029
Alternative minimum tax credit		13,865		-		13,865	indefinite
Arizona coal credits		1,578		1,430		148		2010-2014
Total	$	208,118	$	1,430	$	206,688

At December 31, 2009, NVE had a gross federal NOL carryover of $518.4 million.

Considering all positive and negative evidence regarding the utilization of NVE’s deferred tax assets, it has been determined that NVE is more-likely-than-not to realize all recorded deferred tax assets, except the Arizona coal credits.  As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2009.

   Uncertain tax liabilities are all long term and are included in the “other deferred credits and liabilities” line item on the balance sheet.  A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (dollars in thousands):

	2009			2008
Balance at January 1	$	93,928		$	25,016
Additions based on tax positions related to the current year		3,325			8,855
Additions for tax positions of prior years		11,773			65,426
Reductions for tax positions of prior years		(70,797	)		(5,369	)
Balance at December 31	$	38,229		$	93,928

In December 2007, NVE and the Utilities filed a Form 3115, Application for Change in Accounting Method (“Application”), with the IRS requesting a change in accounting for deducting repair expenditures.  In April 2009, NVE and the Utilities received notice from the IRS approving the Application.  Accordingly, during the second quarter of 2009, NVE, NPC and SPPC recorded reductions to their unrecognized tax benefits for the repair positions taken in the prior period of approximately $64.4 million, $32.0 million and $32.2 million, respectively.  No additional material changes in the income tax reserves are anticipated in the next twelve months.

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively.  The total amount of unrecognized tax benefits as of December 31, 2009 and December 31, 2008 is $38.2 million and $93.9 million, respectively, of which $4.5 million and $3.2 million, respectively, would affect the effective tax rate if recognized.  No interest or penalties have been accrued as of December 31, 2009 and December 31, 2008.  NVE and the Utilities do not expect unrecognized tax benefits to statutorily expire within the next twelve months.

NVE and the Utilities file a consolidated U.S. federal income tax return.  The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE and the Utilities.  As of December 31, 2009, NVE and the Utilities’ tax years 2005 through 2008 are subject to examination.  As of December 31, 2009, NVE and the Utilities are no longer subject to examinations by U.S. federal, state, or local tax authorities for years before 2005, with few exceptions. 

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NPC

The following reflects the composition of taxes on income (dollars in thousands):

	2009			2008			2007
Provisions for income taxes
Current and other
Federal	$	(34,318	)	$	27,038		$	25,351
State		-			-			-
Total current and other		(34,318	)		27,038			25,351
Deferred
Federal		97,878			45,830			58,344
State		256			378			(63	)
Total deferred		98,134			46,208			58,281
Amortization of excess deferred taxes		(862	)		(695	)		(1,236	)
Amortization of investment tax credits		(1,302	)		(1,169	)		(4,044	)
Total provision for income taxes	$	61,652		$	71,382		$	78,352

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):

	2009			2008			2007
Net income	$	134,284		$	151,431		$	165,694
Total income tax expense		61,652			71,382			78,352
Pretax income		195,936			222,813			244,046
Statutory tax rate		35	%		35	%		35	%
Federal income tax expense at statutory rate		68,578			77,985			85,416
Depreciation related to difference in cost basis for tax purposes		1,695			1,209			1,291
AFUDC - equity		(7,359	)		(9,071	)		(5,551	)
Investment tax credit amortization		(1,302	)		(1,169	)		(4,044	)
Regulatory asset for goodwill		1,732			1,732			1,732
Research and development credit		(959	)		(1,078	)		(527	)
Other - net		(733	)		1,774			35
Provision for income taxes	$	61,652		$	71,382		$	78,352
Effective tax rate		31.5	%		32.0	%		32.1	%

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 The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):

	2009			2008
Deferred income tax assets
Net operating loss and credit carryovers	$	115,855		$	1,384
Employee benefit plans		25,176			45,127
Customer advances		14,171			16,019
Gross-ups received on CIAC and customer advances		20,343			21,934
Deferred revenues		4,214			3,549
Reserves		12,144			12,670
Other - net		21,294			21,135
Subtotal		213,197			121,818
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		2,466			3,328
Unamortized investment tax credit		4,683			5,385
Subtotal		7,149			8,713
Total deferred income tax assets before valuation allowance		220,346			130,531
Valuation allowance		(1,430	)		(1,160	)
Total deferred income tax assets after valuation allowance	$	218,916		$	129,371
Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	572,682		$	333,888
Deferred energy		22,692			98,512
Regulatory assets		115,697			97,932
Other - net		70,974			62,374
Subtotal		782,045			592,706
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		173,336			169,506
Total deferred income tax liability	$	955,381		$	762,212
Net deferred income tax liability		570,278		$	472,048
Net deferred income tax liability associated with regulatory matters		166,187			160,793
Total net deferred income tax liability	$	736,465		$	632,841

NPC’s balance sheet contains a net regulatory asset of $166.2 million at December 31, 2009 and $160.8 million at December 31, 2008.  For balance sheet presentation, the regulatory tax asset is included in regulatory assets.  The regulatory tax asset balance consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE.  Offset against these amounts are future revenues to be refunded to customers (regulatory tax liabilities).  For balance sheet presentation, the regulatory tax liability is included in regulatory liabilities.  The regulatory tax liability balance consists of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits.  The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986.  The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment tax credit.

The following table summarizes NPC’s net regulatory tax asset and liability (dollars in thousands):

	2009		2008
Tax benefits flowed through to customers
Related to property	$	82,958	$	76,489
Related to goodwill		90,378		93,017
Regulatory tax asset		173,336		169,506
Liberalized depreciation at rates in excess of current rates		2,466		3.328
Unamortized investment tax credits		4,683		5,385
Regulatory tax liability		7,149		8,713
Net regulatory tax asset	$	166,187	$	160,793

Current income taxes are allocated based on NVE’s and each subsidiaries’ respective taxable income or loss and tax credits as if each subsidiary filed a separate return.

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The following table summarizes as of December 31, 2009 net operating loss and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NPC has determined that realization is uncertain (dollars in thousands):

Type of Carryforward	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Expiration Period
Federal net operating loss	$	106,703	$	-	$	106,703		2022-2029
Research and development credit		7,574		-		7,574		2022-2029
Arizona coal credits		1,578		1,430		148		2010-2014
Total	$	115,855	$	1,430	$	114,425

At December 31, 2009, NPC has a gross federal NOL carryover of $304.9 million.

Considering all positive and negative evidence regarding the utilization of NPC’s deferred tax assets, it has been determined that NPC is more-likely-than-not to realize all recorded deferred tax assets, except for a portion of the Arizona coal credits.  As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2009.

Uncertain tax liabilities are all long term and are included in the “other deferred credits and liabilities” line item on the balance sheet.  A reconciliation of the beginning and ending amount of unrecognized tax benefits for NPC is as follows (dollars in thousands):

	2009			2008
Balance at January 1	$	48,487		$	20,129
Additions based on tax positions related to the current year		2,787			3,549
Additions for tax positions of prior years		9,246			34,353
Reductions for tax positions of prior years		(33,906	)		(9,544	)
Balance at December 31	$	26,614		$	48,487

In December 2007, NVE and the Utilities filed a Form 3115, Application for Change in Accounting Method (“Application”), with the IRS requesting a change in accounting for deducting repair expenditures.  In April 2009, NVE and the Utilities received notice from the IRS approving the Application.Accordingly, during the second quarter of 2009, NPC recorded reductions to its unrecognized tax benefits for the repair positions taken in the prior period of approximately $32.0 million.  No additional material changes in the income tax reserves are anticipated in the next twelve months.

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively.  The total amount of unrecognized tax benefits for NPC as of December 31, 2009 and December 31, 2008 is $26.6 million and $48.5 million, respectively, of which $3.1 million and $2.0 million, respectively, would affect the effective tax rate if recognized.  No interest or penalties have been accrued as of December 31, 2009 and December 31, 2008.  NVE and the Utilities do not expect unrecognized tax benefits to statutorily expire within the next twelve months.

NVE and the Utilities file a consolidated U.S. federal income tax return.  The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE and the Utilities.  As of December 31, 2009, NVE and the Utilities’ tax years 2005 through 2008 are subject to examination.  As of December 31, 2009, NVE and the Utilities are no longer subject to examinations by U.S. federal, state, or local tax authorities for years before 2005, with few exceptions. 

140

SPPC

The following reflects the composition of taxes on income (dollars in thousands):

	2009			2008			2007
Provision for income taxes
Current and other
Federal	$	(488	)	$	13,663		$	57,483
State		12			12			70
Total current and other		(476	)		13,675			57,553
Deferred
Federal		34,335			26,087			(28,705	)
State		292			315			429
Total deferred		34,627			26,402			(28,276	)
Amortization of excess deferred taxes		(847	)		(670	)		(990	)
Amortization of investment tax credits		(2,079	)		(1,804	)		(2,278	)
Total provision for income taxes	$	31,225		$	37,603		$	26,009

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):

	2009			2008			2007
Net Income	$	73,086		$	90,582		$	65,667
Total income tax expense		31,224			37,603			26,009
Pretax income		104,310			128,185			91,676
Statutory tax rate		35	%		35	%		35	%
Federal income tax expense (benefit) at statutory rate		36,509			44,865			32,087
Depreciation related to difference in cost basis for tax purposes		(3,762	)		(77	)		1,679
AFUDC - equity		(1,137	)		(4,383	)		(5,582	)
Investment tax credit amortization		(2,079	)		(1,804	)		(2,278	)
Regulatory asset for goodwill		1,009			1,009			1,009
Research and development credit		(161	)		(232	)		(603	)
Other - net		846			(1,775	)		(303	)
Provision for income taxes	$	31,225		$	37,603		$	26,009
Effective tax rate		29.9	%		29.3	%		28.4	%

As a large corporate taxpayer, the NVE consolidated group’s tax returns are examined by the IRS on a regular basis.  SPPC believes that it has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.

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The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):

	2009		2008
Deferred income tax assets
Credit carryforwards and net operating loss	$	41,282	$	-
Employee benefit plans		37,092		59,083
Customer advances		13,751		14,831
Gross-ups received on CIAC and customer advances		7,776		8,936
Deferred revenues		1,122		1,891
Deferred energy		40,752		9,330
Reserves		1,910		2,542
Other		9,782		6,463
Subtotal		153,467		103,076
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		7,346		8,193
Unamortized investment tax credit		7,634		8,573
Subtotal		14,980		16,766
Total deferred income tax assets	$	168,447	$	119,842
Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	308,600	$	196,161
Regulatory assets		52,132		83,608
Other		23,806		19,798
Subtotal deferred tax liabilities		384,538		299,567
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		88,297		95,273
Total deferred income tax liability	$	472,835	$	394,840
Net deferred income tax liability	$	231,070	$	196,491
Net deferred income tax liability associated with regulatory matters		73,317		78,507
Total net deferred income tax liability	$	304,388	$	274,998

SPPC’s balance sheet contains a net regulatory asset of $73.3 million at December 31, 2009 and $78.5 million at December 31, 2008.  For balance sheet presentation, the regulatory tax asset is included in regulatory assets.  The regulatory tax asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE.  Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities).  For balance sheet presentation, the regulatory tax liability is included in regulatory liabilities.  The regulatory tax liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits.  The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986.  The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment tax credit.

The following table summarizes SPPC’s net regulatory tax asset and liability (dollars in thousands):

	2009		2008
Tax benefits flowed through to customers
Related to property	$	34,254	$	39,678
Related to goodwill		54,043		55,595
Regulatory tax asset		88,297		95,273
Liberalized depreciation at rates in excess of current rates		7,346		8,193
Unamortized investment tax credits		7,634		8,573
Regulatory tax liability		14,980		16,766
Net regulatory tax asset	$	73,317	$	78,507

NVE and its subsidiaries file a consolidated federal income tax return.  Current income taxes are allocated based on NVE’s and each subsidiaries’ respective taxable income or loss and tax credits as if each subsidiary filed a separate return.

The following table summarizes as of December 31, 2009 net operating losses and tax credit carryovers and associated carryover periods for amounts which SPPC has determined that realization is uncertain (dollars in thousands):

142

Type of Carryforward	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Expiration Period
Federal net operating loss	$	37,615	$	-	$	37,615		2010-2014
Research and development credit		3,667		-		3,667		2010-2014
Total	$	41,282	$	-	$	41,282

At December 31, 2009, SPPC has a gross federal NOL carryover of $107.5 million.

Considering all positive and negative evidence regarding the utilization of SPPC’s deferred tax assets, it has been determined that SPPC is more-likely-than-not to realize all recorded deferred tax assets and therefore no valuation allowance has been recorded as of December 31, 2009.

 Uncertain tax liabilities are all long term and are included in the “other deferred credits and liabilities” line item on the balance sheet.  A reconciliation of the beginning and ending amount of unrecognized tax benefits for SPPC is as follows (dollars in thousands):

	2009			2008
Balance at January 1	$	40,126		$	4,430
Additions based on tax positions related to the current year		500			4,536
Additions for tax positions of prior years		2,527			31,709
Reductions for tax positions of prior years		(32,644	)		(549	)
Balance at December 31	$	10,509		$	40,126

In December 2007, NVE and the Utilities filed a Form 3115, Application for Change in Accounting Method (“Application”), with the IRS requesting a change in accounting for deducting repair expenditures.  In April 2009, NVE and the Utilities received notice from the IRS approving the Application.  Accordingly, during the second quarter of 2009, SPPC recorded reductions to its unrecognized tax benefits for the repair positions taken in the prior period of approximately $32.3 million.  No additional material changes in the income tax reserves are anticipated in the next twelve months.

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively.  The total amount of unrecognized tax benefits for SPPC as of December 31, 2009 and December 31, 2008 is $10.5 million and $40.1 million, respectively, of which $1.4 million and $1.2 million, respectively, would affect the effective tax rate if recognized.  No interest or penalties have been accrued as of December 31, 2009 and December 31, 2008.  NVE and the Utilities do not expect unrecognized tax benefits to statutorily expire within the next twelve months.

NVE and the Utilities file a consolidated U.S. federal income tax return.  The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE and the Utilities.  As of December 31, 2009, NVE and the Utilities’ tax years 2005 through 2008 are subject to examination.  As of December 31, 2009, NVE and the Utilities are no longer subject to examinations by U.S. federal, state, or local tax authorities for years before 2005, with few exceptions. 

NOTE 11.                      RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a defined benefit pension plan covering substantially all employees.  Certain grandfathered and certain 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. NVE also has other postretirement plans, including a defined contribution plan which provide medical and life insurance benefits for certain retired employees.

Plan Changes

In September 2009, the postretirement plan for existing retirees in the northern service area was amended to cap company contributions for retiree medical plans at 2009 levels in order to contain costs.  As a result, NVE’s obligation for the postretirement medical plan was re-measured at September 30, 2009, resulting in a reduction to the liability for other postretirement benefits of $24.2 million, and a fourth quarter reduction in pension expense of approximately $1.0 million.  The annual impact of this change is estimated to be $4.0 million.

During 2009, in an effort to reduce costs, NVE implemented severance programs, as discussed in Note 17, Severance Programs, of the Notes to Financial Statements.  Under the terms of the program employees close to retirement age were offered special enhancements to bridge their pension and postretirement benefits.   NVE recognized expense of $0.3 million for pension benefits and $2.8 million for other postretirement benefits in 2009, under the special termination provisions of the Compensation Nonretirement Postemployment Benefits Topic of the FASC.

143

In November 2007, the BOD approved a change in the plan for MPAT employees from a traditional defined benefit pension plan to a defined benefit cash balance pension plan.  Employees with combined age and service totaling 75 years or more had the choice of staying with the current plan or electing to switch to the new plan.  The new plan went into effect on April 1, 2008; all employees hired after that date will be eligible for the cash balance plan, and will be vested after three years of service.  This change, along with market conditions and plan asset values at the time of the re-measurement of the plan obligation, increased 2008 pension expense by $2.7 million over the original estimate of $21.3 million.

Under the terms of NPC’s current contract with IBEW Local No. 396, the pension benefits for those employees covered under that agreement have also changed from a traditional defined benefit plan to a defined benefit cash balance plan effective December 31, 2008.  However, the impact of this change was offset by 2008 market conditions and plan asset values.   NVE did not make any changes to pension plan provisions in 2007 that had significant impacts on recorded pension expense.

In 2008, the postretirement plan was amended to provide that all MPAT employees hired after April 1, 2008 will not be eligible for retiree medical coverage, and those hired after January 1, 2009 will not be eligible for retiree life insurance coverage.  Additionally, all Local Union 396 employees hired after October 13, 2008 will cease to have retiree medical coverage after attaining the age of 65, and they will not be eligible for retiree life insurance coverage.  The impact of these changes on the postretirement plan costs is not known.

In 2007, NVE completed negotiations with SPPC’s bargaining unit 1245 employees, and reached a settlement with regards to postretirement medical coverage.  This agreement resulted in changes to NVE’s future obligations under this plan, and as a result of a re-measurement of the plan obligation, NVE’s 2007 expense was reduced by $1.3 million.

NVE also has a non-qualified Supplemental Executive Retirement Plan and a Restoration Plan for executives. NVE contributed $26.5 million to establish a rabbi trust for these plans in 2009. Assets held in the trust for these non-contributory defined benefit plans consist of a variety of marketable securities and life insurance policies, none of which is NVE stock. At December 31, 2009 trust assets were $26.5 million and are reflected in NVE’s consolidated balance sheet within “Investments and other property, net”. NVE’s obligation under these supplemental and restoration plans is included in “Accrued retirement benefits” in NVE’s consolidated balance sheet, and amounted to $25.1 million at December 31, 2009. NVE is not required to make contributions to the plans.

Benefit Obligations

In 2008, in accordance with the accounting guidance as required by the Compensation Retirement Benefits Topic of the FASC,  NVE, NPC and SPPC recorded additional pension costs of $5.3 million, $3.6 million and $1.4 million, respectively, before taxes, to retained earnings due to the elimination of the early measurement date.  Also in 2008, in accordance with the accounting guidance for compensation retirement benefits, NVE, NPC and SPPC recorded additional post retirement benefit costs of $1.9 million, $0.7 million and $1.1 million, respectively, before taxes, to retained earnings due to the elimination of the early measurement date. These amounts represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007.   NVE has changed the measurement date for its benefit plans from September 30 to December 31, which coincides with NVE’s fiscal year end.  The following tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans.  These reconciliations are based on a December 31 measurement date for 2009 and 2008, and a September 30 measurement date for 2007 (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
	2009			2008			2009			2008
Change in benefit obligations
Benefit obligation, beginning of year	$	727,472		$	674,687		$	176,059		$	150,175
Effect of Eliminating Early Measurement Date		-		$	10,708			-		$	2,438
Service cost		18,838			21,748			2,421			2,562
Interest cost		44,145			42,818			10,072			10,732
Plan Participants' contributions		-			-			1,677			1,475
Actuarial loss (gain)		7,054			38,174			7,617			(7,567	)
Gross Benefits paid		(40,077	)		(31,944	)		(10,953	)		(11,838	)
Administrative Expenses		-			(455	)		-			-
Plan amendments		-			(28,264	)		(35,507	)		4,562
Special Termination Benefits		316			-			2,818			-
Change in Estimates		-			-			-			23,520
Remeasurement Adjustment		-			-			83			-
Benefit obligation, end of year	$	757,748		$	727,472		$	154,287		$	176,059

The accumulated benefit obligation for Pension Benefits at the end of 2009 and 2008 was $701 million and $659 million respectively.

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The actuarial assumptions used to determine end of year benefit obligations were as follows:

			Other Postretirement
	Pension Benefits		Benefits
	2009	2008	2009	2008
Discount rate	5.80%	6.09%	5.75%	6.07%
Rate of compensation increase	4.50%	4.50%	N/A	N/A

In selecting an assumed discount rate for fiscal year 2009 pension cost and for fiscal year-end 2009 disclosures, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.

For measurement purposes, the following assumptions were used regarding health care cost trend rates at December 31:

	2009	2008
Health care cost trend rate assumed for year	8.00%	8.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend rate	2016	2014

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:

Effect on the postretirement benefit obligation	2009			2008
Effect of a 1-percentage point increase	$	8,294		$	14,407
Effect of a 1-percentage point decrease	$	(6,657	)	$	(12,333	)

Plan Assets

NVE’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan.  NVE contributed a total of $53.5 million in 2009 towards the pension plans.

NVE strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets.  Also, NVE considers the ability of the plan to pay all benefit and expense obligations when due, and to control the costs of administering and managing the plan.  NVE’s investment guidelines prohibit investing the plan assets in real estate and NVE’s stock.

NVE’s long term strategy for the pension plan assets is to maximize risk adjusted returns while maintaining adequate liquidity to pay plan benefits.  NVE is committed to prudent investments with ample diversification in terms of asset types, fund strategies, and investment managers.  NVE has increased the target allocation of fixed income from 40% to 70% in order to minimize the earnings volatility of plan assets to match its liabilities.  As such, NVE has elected to include an appropriate mix of indexed and actively managed investments to accomplish its strategy.  The current allocation for pension plan net assets at December 31, 2009 is 44% fixed income, 36% domestic equity, 13% international equity, and 7% cash.  The long-term target allocation for pension plan net assets is 70% fixed income, 17% U.S. equity, 8% international equity, and 5% other (cash and alternative investments).  The fixed income investments are benchmarked against government and corporate credit bond indices.  U.S. equity investments include large cap, mid-cap, and small-cap companies with an emphases towards small and mid-cap investments relative to the Russell 2500 Growth Index.  International equity is currently actively managed and includes investments in both established and emerging markets.

The current allocation for the other post-retirement benefit plan net assets at December 31, 2009 is 60% equity securities, 36% fixed income and 4% cash.  The long term strategy for the other post-retirement benefit plan net assets is similar to the pension plan net assets strategy as described above. The target allocation for other post-retirement benefit assets is 60% equity and 40% fixed income. The equity is invested in indexed securities that track the S&P 500 Index.  The fixed income is indexed and benchmarked against government and corporate credit bond indices.

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The fair values of NVE’s pension plan and other postretirement benefits assets at December 31, 2009, within the fair value hierarchy as required by the Fair Value Measurements and Disclosures Topic of the FASC, by asset category are as follows (dollars in thousands):

   Pension Plan Assets

	Fair Value Measurements at December 31, 2009
Asset Category	Level 1		Level 2		Level 3		Total
Cash & Cash equivalents (1)	$	6,751	$	57,628		-	$	64,379
Equity:
U.S. Equity Securities (2)		213,085		-		-		213,085
International Equity Securities		108,779		-		-		108,779
Fixed Income:
U.S. Preferred Securities		179		-		-		179
International Preferred Securities		419		-		-		419
U.S. Fixed Income Securities (3)		55,728		224,157		457		280,342
International Fixed Income Securities		-		22,542		-		22,542
Other:
U.S. Future Contracts		7		-		-		7
International Future Contracts		29		-		-		29
U.S. Convertible Securities		-		175		-		175
Total (4)	$	384,977	$	304,502	$	457	$	689,936

   Other Postretirement Benefit Assets

	Fair Value Measurements at December 31, 2009
Asset Category	Level 1		Level 2		Level 3		Total
Cash & Cash equivalents (1)	$	218	$	3,877	$	-	$	4,095
Equity:
U.S. Equity Securities (2)		58,714		-		-		58,714
International Equity Securities		3,519		-		-		3,519
Fixed Income:
U.S. Preferred Securities		6		-		-		6
International Preferred Securities		14		-		-		14
U.S. Fixed Income Securities (3)		1,803		25,016		15		26,834
International Fixed Income Securities		-		729		-		729
Other:
International Future Contracts		1		-		-		1
U.S. Convertible Securities		-		5		-		5
Total (4)	$	64,275	$	29,627	$	15	$	93,917

(1)	Level 1 investments are comprised of U.S. Treasury bills.  Level 2 investments consist of commingled funds that are primarily comprised of money market holdings and marketable securities, U.S. Treasury bills and commercial paper valued and redeemable at cost.
(2)	This category includes approximately 45% large-cap, 27% mid-cap, 9% small cap, and 19% broad market domestic equity investments.
(3)	Level 1 investments are comprised of fixed income securities that mainly invest in U.S. Treasury bills.  Level 2 investments consist of commingled funds that track either the Barclays Capital Aggregate Bond Index or Barclays Capital Long Government and Corporate Credit Index.  Level 3 investments are comprised of corporate loans.
(4)	The fair value of NVE’s pension plan and postretirement benefit assets does not reflect approximately $19.1 million and $0.6 million, respectively, in administrative trust net liabilities.  As such, the fair value of the plans assets for both pension and postretirement benefits net of the $19.1 million and $0.6 million liability is approximately $670.8 million and $93.3 million, respectively, at December 31, 2009.

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The following table shows the change in plan net assets for 2009 and 2008.  Employer contributions reflect funding and benefit payments made by NVE (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
	2009			2008			2009			2008
Change in plan net assets
Fair value of plan net assets, beginning of year	$	531,373		$	639,996		$	84,661		$	108,921
Effect of Eliminating Early Measurement Date		-			6,893			-			1,202
Actual return on plan assets		123,693			(181,760	)		17,619			(23,280	)
Employer contributions		55,805			94,143			294			8,181
Plan participants' contributions		-			-			1,677			1,475
Gross benefits paid		(40,077	)		(27,444	)		(10,953	)		(11,838	)
Expenses paid		-			(455	)		-			-
Fair value of plan net assets, end of year	$	670,794		$	531,373		$	93,298		$	84,661

The expected long-term rate of return on the pension and other postretirement benefit plan assets is 6.75%, 7.10% and 8.00%, and 7.10%, 7.10% and 8.00%, respectively, in 2010, 2009 and 2008, respectively.

Funded Status

The following table shows the funded status of each of the plans for 2009 and 2008 (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
Funded Status, end of year:	2009			2008			2009			2008
Fair value of plan net assets	$	670,794		$	531,373		$	93,298		$	84,660
Benefit obligations	$	(757,748	)	$	(727,472	)	$	(154,287	)	$	(176,059	)
Funded status	$	(86,954	)	$	(196,099	)	$	(60,989	)	$	(91,399	)

Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
Amounts recognized in the statement of financial position consist of:	2009			2008			2009			2008
Current liability		(1,519	)		(1,561	)		-			-
Noncurrent liability		(85,435	)		(194,537	)		(60,989	)		(91,399	)
Net amount recognized	$	(86,954	)	$	(196,098	)	$	(60,989	)	$	(91,399	)

The following amounts would have been recognized in Accumulated Other Comprehensive Income, net of taxes, according to the provisions of the Compensation Retirement Benefits Topic of the FASC.  Since NVE is able to recover expenses through rates, the amounts will be recorded as Other Regulatory Assets under the provisions of the Regulated Operations Topic of the FASC (dollars in thousands).

							Other Postretirement
	Pension Benefits						Benefits
Amounts recognized as other regulatory assets:	2009			2008			2009			2008
Net actuarial (gain)/loss	$	249,793		$	355,553		$	71,229		$	80,836
Prior service (credit)/cost		(15,753	)		(16,965	)		(40,377	)		(5,880	)
	$	234,040		$	338,588		$	30,852		$	74,956

The estimated amounts that will be amortized from other regulatory assets and accumulated other comprehensive income into net periodic cost in 2010 are as follows (dollars in thousands):

	Pension Benefits			Other Postretirement Benefits
Actuarial (gain)/loss	$	15,068		$	4,318
Prior service (credit)/cost		(1,794	)		(3,890	)

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At the end of 2009 and 2008, the projected benefit obligation, accumulated benefit obligation, and fair value of plan net assets for pension plans with a projected benefit obligation in excess of plan net assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):

	Benefit Obligation Exceeds				Accumulated Benefit Obligation Exceeds
	the Fair Value of Plan's Assets				the Fair Value of Plan's Assets
	2009		2008		2009		2008
Projected benefit obligation, end of year	$	757,748	$	727,472	$	-	$	-
Accumulated benefit obligation, end of year		-		-		700,665		659,404
Fair value of plan net assets, end of year		670,794		531,373		670,794		531,373

The expected cash flows for the plans, including trust accounts, are as follows (dollars in thousands):

	Pension Benefits		Other Postretirement Benefits
Company contributions
2010 (expected)	$	41,519	$	294
			Gross		Expected Federal Subsidy
Expected benefit payments
2010		70,117		9,802		-
2011		44,711		10,422		-
2012		47,110		10,642		-
2013		50,218		10,480		-
2014		51,746		10,456		-
2015-2019		272,475		52,884		-

The above benefit payments are obligations of the indicated plan, and reflect payments which do not include employee contributions.  The expected benefit payment information that reflects the employee obligation is almost exclusively paid from plan assets.  A small portion of the pension benefit obligation is paid from the plan sponsor’s assets.

Net Periodic Cost

The components of net periodic pension and other postretirement benefit costs for NVE, NPC and SPPC are presented below (dollars in thousands):

	Pension Benefits									Other Postretirement Benefits
NV Energy, consolidated	2009			2008			2007			2009			2008			2007
Service cost	$	18,837		$	21,748		$	22,901		$	2,421		$	2,562		$	2,680
Interest cost		44,145			42,818			39,420			10,072			10,732			10,088
Expected return on plan assets		(37,159	)		(47,051	)		(41,895	)		(6,048	)		(8,351	)		(5,182	)
Amortization of:
Actuarial (gain)/loss		27,575			6,714			7,211			5,296			3,489			3,413
Prior service (credit)/cost		(1,794	)		(166	)		1,629			(1,466	)		(1,028	)		(225	)
Transition (asset)/obligation		-			-			-			-			-			484
Settlement (gain)/loss		-			-			4,441			-			338			-
Remeasurement Adjustment		-			-			-			336			-			-
Total net benefit cost	$	51,604		$	24,063		$	33,707		$	10,611		$	7,742		$	11,258

The NVE total net periodic cost excludes special termination benefits of $0.3 million for pension and $2.8 million for other postretirement benefits, related to severance programs implemented in 2009.  See Note 17, Severance Programs, of the Notes to Financial Statements for further discussion.

The average percentage of NVE net periodic costs capitalized during 2009, 2008 and 2007 was 36.6%, 37.1% and 34.7%, respectively.

148

	Pension Benefits									Other Postretirement Benefits
Nevada Power Company	2009			2008			2007			2009			2008			2007
Service cost	$	9,572		$	12,798		$	13,092		$	1,325		$	1,217		$	1,079
Interest cost		21,079			21,240			18,977			2,437			2,524			2,178
Expected return on plan assets		(17,847	)		(22,554	)		(19,000	)		(2,067	)		(2,702	)		(1,232	)
Amortization of:
Actuarial (gain)/loss		13,192			3,321			-			1,272			808			729
Prior service (credit)/cost		(1,733	)		57			1,430			1,104			1,157			606
Transition (asset)/obligation		-			-			3,429			-			-			485
Remeasurement Adjustment		-			-			-			57			-			-
Total net benefit cost	$	24,263		$	14,862		$	17,928		$	4,128		$	3,004		$	3,845

The average percentage of NPC net periodic costs capitalized during 2009, 2008 and 2007 was 39.4%, 40.5% and 38.8%, respectively.

	Pension Benefits									Other Postretirement Benefits
Sierra Pacific Power Company	2009			2008			2007			2009			2008			2007
Service cost	$	8,245		$	7,998		$	8,553		$	1,028		$	1,275		$	1,542
Interest cost		21,885			20,248			19,100			7,567			8,054			7,844
Expected return on plan assets		(18,321	)		(23,270	)		(21,969	)		(3,894	)		(5,512	)		(3,823	)
Amortization of:
Actuarial (gain)/loss		13,701			3,085			-			3,990			2,633			2,663
Prior service (credit)/cost		(104	)		(137	)		212			(2,586	)		(2,201	)		(831	)
Transition (asset)/obligation		-			-			3,467			-			-			-
Remeasurement Adjustment		-			-			-			277			-			-
Total net benefit cost	$	25,406		$	7,924		$	9,363		$	6,382		$	4,249		$	7,395

The average percentage of SPPC net periodic costs capitalized during 2009, 2008 and 2007 was 36.4%, 36.5% and 35.7%, respectively.

The weighted-average assumptions used to determine net periodic cost are as follows:

							Other Postretirement
	Pension Benefits						Benefits
	2009		2008		2007		2009			2008		2007
Discount rate		6.09%		6.38%		6.00%		6.07%	(1)		6.25%		6.00%
Expected Return on Plan Assets		7.10%		8.00%		8.00%		7.10%			8.00%		8.00%
Rate of compensation increase		4.50%		4.50%		4.50%		N/A			N/A		N/A

(1) A discount rate of 5.37% was used for the September 30, 2009 remeasurement.

For measurement purposes, the following assumptions were used regarding health care cost trend rates at December 31:

	2009	2008
Health care cost trend rate assumed for year	8.50%	8.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend rate	2015	2014

The assumed health care cost trend rate has a significant effect on the amounts reported.  A one percentage point change in the assumed health care cost trend rate would have had the following effect:

One percentage point change:	2009			2008			2007
Effect on total of service and interest cost components
Effect of a 1-percentage point increase in health care trend		1,005			1,130			1,476
Effects of a 1-percentage point decrease in health care trend		(788	)		(947	)		(1,210	)

149

 The expected ROR on plan assets was determined by considering a realistic projection of what assets can earn, given existing capital market conditions, historical equity and bond premiums over inflation, the effect of “normative” economic conditions that may differ from existing conditions, and projected ROR on reinvested assets.

There were no significant transactions between the plan and the employer or related parties during 2009, 2008, or 2007.

NOTE 12.                       STOCK COMPENSATION PLANS

At December 31, 2009, NVE had several stock-based compensation plans, which are described below.

NVE’s executive long-term incentive plan for key management employees, which was approved by shareholders in May 2004, provides for the issuance of up to 7,750,000 of NVE’s common shares to key employees through December 31, 2013.  The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2009, NVE granted restricted shares and performance shares under the long-term incentive plan.

NVE recorded $6.8 million, $4.1 million and $8.5 million as stock compensation expense in 2009, 2008 and 2007, respectively.

Non-Qualified Stock Options

Elected officers and key employees specifically designated by a committee of the BOD are eligible to be awarded non-qualified stock options (NQSO’s) based on the guidelines in the plan. These grants are at 100% of the then current fair market value, and vest over different periods as stated in the grant. These options have to be exercised within ten years of award, and no earlier than one year from the date of grant.  At the time of grant, rights to dividend equivalents may be awarded; however, historically, dividend equivalents have not been granted.

In 2009 and 2008, there were no grants of non-qualified stock options made to employees.  The total number of non-qualifying stock options granted to all employees in 2007 was 411,036, which were issued at an option price not less than market value at the date of grant.  Of this amount, 409,934 will vest over three years from the grant date at one-third per year.   The remaining 1,102, granted on November 1, 2007 will vest over three years beginning on February 15, 2008.  The grants may be exercised for a period not exceeding ten years from the grant date. The options may be exercised using either cash or previously acquired shares valued at the current market price, or a combination of both.  The Committee also allows cashless exercises, subject to applicable securities law restrictions or other means consistent with the purpose of the plan and the applicable law.

150

A summary of the status of NVE’s nonqualified stock option plan as of December 31, 2009, 2008, and 2007, and changes during the year is presented below:

	2009				2008				2007
			Weighted-				Weighted-				Weighted-
			Average				Average				Average
Nonqualified Stock Options	Shares		Exercise Price		Shares		Exercise Price		Shares		Exercise Price
Outstanding at beginning of year		1,278,557	$	15.65		1,294,397	$	15.77		1,199,188	$	14.66
Granted		-		-		-		-		411,036	$	18.25
Exercised		8,000	$	7.35		-		-		312,639	$	14.82
Forfeited		415,840	$	16.31		15,840	$	24.93		3,188	$	19.97
Outstanding at end of year		854,717	$	15.40		1,278,557	$	15.65		1,294,397	$	15.77
Options exercisable at year-end		717,705	$	14.84		956,431	$	14.94		747,317	$	14.94
Intrinsic value of options exercised	$	21,120			$	-			$	1,381,976
Fair value of options vested	$	-			$	-			$	-
Weighted-average grant date fair
value of  options granted 1:
Average of all grants for:
2009	$	0.00
2008					$	0.00
2007									$	6.27

(1) The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants issued in 2007: Average Dividend Yield, 0%, Average Expected Volatility, 24.23%, Average Risk-Free Rate of Return, 4.41%, and Average Expected Life, 6 years.

The following table summarizes information about nonqualified stock options outstanding at December 31, 2009:

			Options Outstanding				Options Exercisable
									Number
			Number				Weighted		Vested and
	Weighted Average		Outstanding		Remaining		Average		Exercisable at
Year of Grant	Exercise Price		At 12/31/09		Contractual Life		Exercise Price		12/31/09
2000	$	16.00		20,600	<1 year		$	16.00		20,600
2001	$	15.08		22,510	1 years		$	15.08		22,510
2002	$	14.05		78,410	2- 2.5 years		$	14.05		78,410
2004	$	7.29		25,000	4.5 years		$	7.29		25,000
2005	$	10.10		126,966	5.2 - 5.4 years		$	10.10		126,966
2006	$	13.29		170,195	6.1 years		$	13.29		170,195
2007	$	18.25		411,036	7.1 -7.8 years		$	18.25		274,024
Weighted Average Remaining Contractual Life
						5.84				5.54
Intrinsic Value	$	416,732					$	416,732

The total amount of NQSO compensation expense recognized in 2009, 2008 and 2007 was $0.4 million, $1.0 million and $1.5 million, respectively.  Dividend Equivalents were not granted for any of these awards.

151

Performance Shares

In 2009, 2008 and 2007, NVE granted performance shares in the following numbers and initial values:

	2009		2008		2007
Shares Granted		895,803		518,121		138,967
Fair value per Share	$	10.90	$	15.27	$	16.96

              In 2009, 2008 and 2007, 895,803, 518,121 and 138,967 shares of stock, respectively, were granted to plan participants; the actual number of shares earned by each participant is dependent upon NVE achieving certain financial goals over three-year performance periods.  The value of all performance share grants, if earned, will be equal to the market value of NVE's common shares as of the end of the performance periods.  NVE, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof.

In 2006, there were 2,610 special grant shares awarded, which were to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant.  The shares for this grant were earned and issued in 2007.

In August, 2006, upon the signing of an employment agreement for the prior Chief Executive Officer, a grant of 500,000 performance shares was issued according to the agreement. The grant requires the achievement of specific performance goals which were established in the agreement. The final determination and approval of the number of shares awarded was at the discretion of the BOD and the Compensation Committee.  In 2007, 200,000 shares were deemed to have been earned and were issued in the form of cash.

There were 42,920 special grant shares awarded in 2005, which were to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant. These shares were earned and issued in 2007.

In 2005, there were 182,114 performance shares awarded, and due to the achievement of certain performance goals established for this grant over a three year cycle, the number of shares available under this grant was increased to 224,591; these shares were issued in early 2008.

In 2006, there were 162,008 performance shares awarded, and at the discretion of the BOD and the Compensation Committee, it was determined that the performance goals established for this grant over a three year cycle, were not achieved and the shares were forfeited in early 2009.

In accordance with the Stock Compensation Topic of the FASC, NVE recognized expense in 2009, 2008 and 2007 related to performance shares.  Expense was recognized using the closing market price of NVE stock at the end of each interim period and on December 31, 2009.

The total fair value of shares issued in 2009, 2008 and 2007 were $0, $3.8 million and $4.4 million, respectively.  The total fair value of shares vested in 2009, 2008, and 2007 were $5.4 million, $2.5 million and $3.1 million, respectively.

Restricted Stock Shares

In 2009, NVE awarded several grants of restricted shares; 63,000 shares were awarded with a grant price of $10.91 per share, 2,000 shares were awarded with a grant price of $11.57 per share, and 1,000 shares were awarded with a grant price of $11.71 per share.  These grants will vest equally over three years from the date of grant.  The issuance of these shares is conditional upon the employee retaining employment with NVE throughout the entire vesting period.

In 2008, NVE awarded several grants of restricted shares; 30,000 shares were awarded with a grant price of $14.39 per share, 10,000 shares were awarded with a grant price of $10.73 per share, and 3,500 shares were awarded with a grant price of $8.07 per share.  These grants will vest equally over three years from the date of grant.  The issuance of these shares is conditional upon the employee retaining employment with NVE throughout the entire vesting period.

There were no restricted shares granted in 2007.

In 2006, 5,643 shares of restricted stock were awarded at a grant price of $13.29 per share; this grant was fully vested on December 31, 2006 and the shares were issued in early 2007.

The total fair value of shares issued in 2009, 2008 and 2007 were $0, $0 and $6.0 million, respectively.  The total fair value of shares vested in 2009, 2008 and 2007 were $0.5 million, $0.3 million and $3.7 million, respectively.

152

Employee Stock Purchase Plan

Upon the inception of NVE’s employee stock purchase plan, NVE was authorized to issue up to an aggregate of 200,162 shares of common stock to all of its employees with minimum service requirements. On June 19, 2000, shareholders approved an additional 700,000 shares for distribution under the plan. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase NVE’s common stock. In 2008, the BOD of NVE and its stockholders, approved changes to the plan which increased the option price discount from 10% to 15%, and provided for the purchase price to be the lesser of 85% of the market value on the offering commencement date, or 85% of the market value on the offering exercise date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan NVE sold 178,152, 109,924 and 56,835 shares to employees in 2009, 2008 and 2007, respectively.

In accordance with the Stock Compensation Topic of the FASC, NVE recognized expense in 2009, 2008 and 2007 related to the employee stock purchase plan.  For purposes of determining the expense for those years, compensation cost has been estimated for the employees’ purchase rights on the date of grant, using the Black-Scholes option-pricing model with the following assumptions used for 2009, 2008 and 2007, with an option life of six months:

Year	Average Dividend Yield			Average Expected Volatility			Average Risk-Free Rate of Return			Weighted Average Fair Value
2009		3.90	%		28.89	%		0.22	%	$	2.54
2008		0.00	%		40.31	%		1.22	%	$	2.56
2007		0.00	%		20.75	%		4.13	%	$	3.02

NOTE 13.                      COMMITMENTS AND CONTINGENCIES

Purchased Power

The Utilities have several contracts for long-term purchase of electric energy.  Expiration of these contracts ranges from 2010 to 2039.  Related party purchase power agreements have been eliminated from the NVE totals.  Estimated future commitments under non-cancelable agreements as of December 31, 2009 were as follows (dollars in thousands):

	Purchased Power
	NPC		SPPC		NVE
2010	$	415,331	$	177,295	$	495,126
2011		375,340		176,400		449,957
2012		384,315		173,788		455,392
2013		388,639		175,180		460,171
2014		371,092		180,820		447,317
Thereafter		4,034,236		2,336,732		4,682,309

Coal, Natural Gas and Transportation

The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas.  These contracts expire in years ranging from 2010 to 2031.  Estimated future commitments under non-cancelable agreements as of December 31, 2009 were as follows (dollars in thousands):

	Coal and Natural Gas						Transportation
	NPC		SPPC		NVE		NPC		SPPC		NVE
2010	$	472,859	$	209,751	$	682,610	$	48,462	$	73,588	$	122,050
2011		55,133		44,564		99,697		52,039		65,401		117,440
2012		-		15,831		15,831		75,191		44,777		119,968
2013		-		14,906		14,906		75,065		44,156		119,221
2014		-		14,906		14,906		74,076		44,156		118,232
Thereafter		-		13,249		13,249		877,324		208,248		1,085,572

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Long-Term Service Agreements

NPC entered into long-term service agreements for the performance of maintenance on generation units located at the Lenzie Generating Station, the Silverhawk Generating Station and the Higgins Generating Station.  SPPC entered into a long-term service agreement for the Tracy Generating Station.  Future commitments under these agreements are as follows (dollars in thousands):

	Long-Term Service Agreements
	NPC		SPPC		NVE
2010	$	25,202	$	5,631	$	30,833
2011		25,202		5,631		30,833
2012		25,202		5,631		30,833
2013		25,202		5,631		30,833
2014		25,202		5,631		30,833
Thereafter		89,038		33,784		122,822

Capital Projects

Capital projects at NPC include construction of the Harry Allen Generating Station, and the construction of a Recovered Energy Generation Project.  Future commitments under these agreements are as follows (dollars in thousands):

	Capital Projects
	NPC		SPPC		NVE
2010	$	165,496	$	-	$	165,496
2011		8,121		-		8,121
2012		-		-		-
2013		34,397		-		34,397

 Operating Leases

NPC and SPPC have entered into various operating leases for buildings, land and equipment.  Rent payments for 2009, 2008 and 2007 were$13.8 million, $10.8 million and $5.7 million, respectively, for NPC.  Rent payments for 2009, 2008 and 2007 were $13.9 million,$12.1 million and $10.5 million, respectively, for SPPC.  NVE’s, NPC’s and SPPC’s estimated future minimum cash payments under non-cancelable operating leases as of December 31, 2009, were as follows (dollars in thousands):

	Operating Leases
	NPC		SPPC		NVE
2010	$	12,648	$	13,745	$	26,393
2011		10,341		8,526		18,867
2012		8,373		7,162		15,535
2013		7,981		6,529		14,510
2014		7,183		5,741		12,924
Thereafter		64,202		39,872		104,074

Environmental

   NPC

      Reid Gardner Generating Station

         Surface and Groundwater Matters

The Reid Gardner Generating Station is a coal generating station consisting of four units.  NPC is the owner and operator of Unit Nos. 1, 2 and 3.  Unit No. 4 is co-owned by the CDWR 67.8% and 32.2% by NPC.  NPC is the operating agent for Unit No. 4.

The Reid Gardner Generating Station has a number of raw water and scrubber make-up storage ponds, as well as lined ponds used for process water evaporation.  Process water, which has been used beyond the treatable limits, is routed to lined onsite ponds for evaporation.  Solid waste management units are present throughout the site and surrounding area.  Environmental contaminants identified at the Reid Gardner Generating Station include but are not limited to, elevated concentrations of total dissolved solids, sulfate, chloride, dissolved metals, volatile organic compounds and petroleum hydrocarbons.

In August 1999, the NDEP issued a discharge permit to the Reid Gardner Generating Station and an Order that requires all evaporation and fly ash settling ponds to be closed or lined with impermeable liners over the next ten years.  This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts.  This plan has been reviewed and approved by NDEP.  In

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collaboration with NDEP, NPC has evaluated remediation requirements.  In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area.  Any future ponds will be double-lined with inter-liner leak detection in accordance with the most recent NDEP Authorization to Discharge Permit issued October 2005.

Pond construction and lining costs to satisfy the NDEP order expended through December 31, 2009 was approximately $42.0 million. No additional expenditures associated with this order are projected as the final pond was closed per the requirements of the order on October 21, 2009.

In 2006 NPC and the Corrective Actions Division of NDEP began discussions regarding what additional soil and groundwater remediation may be required at the site, beyond the scope of the current pond relining project.  The proposed solution was to enter into an Administrative Order of Consent (AOC), which was delivered in final form to NPC in December 2007. 

In February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4.  Furthermore, the AOC has been designed to supersede previous Orders and takes a comprehensive approach to address historical environmental impacts associated with facility operations.   As a result, NPC has recorded an asset retirement obligation as referenced in Note 1, Summary of Significant Accounting Policies of the Notes to the Financial Statements and capital and remediation costs of approximately $32.3 million in addition to a 2008 charge to operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is further defined and additional characterization has been completed.

         Air Quality Matters

In June 2006, the EPA issued a Finding and Notice of Violation (NOV) related to monitoring, recordkeeping and emission exceedances at the Reid Gardner Generating Station.  In April 2007, NPC lodged a Consent Decree in federal district court with NDEP, EPA and the Department of Justice regarding the NOVs and providing for additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures required to resolve the alleged violations.  Terms of the Consent Decree included a $1.1 million fine, which was paid during 2007, funding of an approximately $2 million Supplemental Environmental Project (SEP) with the Clark County School District, and the installation of emission reduction equipment at the facility.  The SEP was aimed at achieving increased energy efficiency and cost savings for the school district and involved extensive lighting retrofits at multiple schools in the Las Vegas valley.  Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations, and which satisfied the terms of the consent decree, were previously submitted by NPC to the PUCN in NPC’s 2006 IRP filing.  Installation of the required environmental controls was fully completed in 2009.  These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen.  Capital expenditures are estimated at $92.3 million, of which $84 million was approved by the PUCN in NPC’s 2006 IRP, which is still subject to prudency review.  NPC will seek full recovery of these amounts in a future GRC filing.  

      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.

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Litigation Contingencies

   NPC and SPPC

      Calpine Settlement

On September 19, 2007, NPC, SPPC and Calpine entered into a settlement agreement (the “Settlement Agreement”) that resolved the issues and claims pertaining to three proofs of claim (Claim Nos. 5177, 5178 and 5179) filed by the Utilities against Calpine in Calpine’s bankruptcy proceeding.  The Settlement Agreement was approved by the United States Bankruptcy Court for the Southern District of New York on October 10, 2007, and by the FERC on December 28, 2007, in orders that are final and non-appealable.

Claim Nos. 5177 and 5179 filed by SPPC and NPC relate to complaints filed with FERC in  December 2001 under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in reaction to the Western United States energy crisis.  The Settlement Agreement provided that, for Claim Nos. 5177 and 5179, SPPC and NPC would receive general unsecured claims in the Calpine bankruptcy proceeding of approximately $1.7 million and $1.3 million respectively, totaling $3 million.  In February 2008, Calpine distributed shares of Calpine common stock to SPPC and NPC with respect to Claim Nos. 5177 and 5179, at the approximate value at the time of the distribution of approximately $1.3 million, and $1.1 million, respectively.  The Utilities recognized these amounts as income for the year ended December 31, 2008.

Claim No. 5178 filed by NPC regarding Calpine’s alleged breach of a 400 MW TSA and a 2002 settlement agreement approved by the FERC.  The Settlement Agreement provided that the claim shall be amended to reflect a general unsecured claim of $18 million against Calpine.  NPC agreed to treat the distribution in respect to Claim No. 5178 as a prepayment for a new 400 MW TSA (“New TSA”) with a term commencing January 1, 2008 and ending approximately March 31, 2010, assuming no change in NPC’s OATT service schedules and, in the event of any such changes, ending on the date the $18 million is depleted based on the applicable OATT service rate schedule.  In February 2008, Calpine distributed shares of Calpine common stock to NPC having an approximate value at that time of $14.4 million, which will be recognized as transmission revenue over the term of the new TSA.

The distributions discussed above represent approximately 80% of the balance owed to NPC and SPPC under the three proofs of claims filed.  Management cannot predict if the remaining 20% will be recovered due to the status of Calpine’s bankruptcy proceedings, and as such has not recorded any further amounts as income.  Subsequent to the distribution, NPC and SPPC sold all of their shares of Calpine common stock and recorded a gain of $1.8 million for the year ended December 31, 2008.

   NPC

      Lawsuit Against Natural Gas Providers

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

      Peabody Western Coal Company

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

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      Royalty Claim

On October 15, 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Co. (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and 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.  The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease.  In July 2001, the U.S. District Court dismissed all claims against Salt River.  The action had been stayed since October, 2004 until March, 2008, when the U.S. District Court lifted the stay and referred pending discovery related motions to a Magistrate judge.   Those discovery motions have now been resolved and the Court ordered substantial completion of factual discovery (except for certain depositions) by July 15, 2010. Management cannot predict the timing or outcome of a decision on this matter.

         Retiree Health Care and Reclamation Claims

In addition to the above action before the Missouri State Court, Peabody further asserted in 1994 that the Navajo Joint Owners are liable under the CSA for Retiree Health Care Costs (RHCC) and Final Reclamation Costs (FRC), which Peabody WC is obligated to pay after the CSA expires and the Kayenta Mine closes.  In 1996, Salt River and the Navajo Joint Owners filed a complaint in the Maricopa County (Arizona) Supreme Court seeking determinations that they are not liable for RHCC or FRC or, alternatively, that Peabody WC cannot recover RHCC and FRC until after the CSA ends.  The case was dormant for several years, while Peabody WC pursued other RHCC and FRC claims arising out of similar coal contracts.  Settlement discussions, led by Salt River on both the RHCC matter and the FRC claim reached final approvals with Peabody WC and the Navajo Joint Owners in July 2008 (Settlement Agreement and Mutual Release with Peabody).  As of December 31, 2009, NPC has a $17.4 million liability recorded which management has assessed as the approximate amount to be paid, and recorded a corresponding other regulatory asset for such claims, as management believes that these costs are recoverable through deferred energy.  The underlying lawsuit and arbitration have both been dismissed.

   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 (Order). In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the U.S. Court of Appeals for the Ninth Circuit

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(Ninth Circuit Court). Subsequently, in August 2009, the Insurers appealed the District Court’s insurance coverage decision with the Ninth Circuit Court. In January 2010, the Ninth Circuit Court ordered the parties to complete briefing on both appeals by April 2010.

Other Legal Matters

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

NOTE 14.      COMMON STOCK AND OTHER PAID-IN CAPITAL

Rights Agreement  

In December 2005, the BOD voted to amend the Rights Agreement, dated as of February 2001 (as amended and restated, the “Rights Agreement”), between NVE and Wells Fargo Bank Minnesota, N.A., to accelerate the final expiration date of the rights (“Rights”) issued thereunder to December 2005, and to terminate the Rights Agreement upon the expiration of the Rights.  The BOD also adopted a policy governing future entry into a shareholder rights agreement or similar agreement (a “shareholder rights plan”).  NVE’s policy is to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the BOD, in the exercise of its fiduciary duties and with the concurrence of a majority of its independent members, determines that, under the circumstances existing at the time, it is in the best interest of NVE’s shareholders to adopt a shareholder rights plan without first obtaining shareholder approval.  If a shareholder rights plan is adopted without prior shareholder approval, the plan must provide that it shall expire, unless ratified by shareholders, within one year of adoption.

Stock Ownership Plans  

As of December 31, 2009, 10,956,240 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees’ Stock Purchase Plan (ESPP), and Executive Long-Term Incentive Plan (LTIP).

The 2005 LTIP for officers and key employees allows for the issuance of NVE’s common shares through December 2013, which can be earned and issued prior to December 2013.  This Plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares, bonus stock and cash.

NVE also provides an ESPP to all of its employees meeting minimum service requirements.  Employees can choose twice each year (offering date) to have up to 15% of their base earnings withheld to purchase NVE common stock.  The purchase price of the stock is 85% of the market value on the offering date or the execution date, whichever is less.

Non-Employee Director Stock  

The Non-employee Director Stock Plan provides that a portion of NVE’s outside directors’ annual retainer be paid in NVE common stock.  In addition, in 1996, NVE eliminated its outside director retirement plan and converted the present value of each director’s vested retirement benefit to phantom stock based on the stock price at the time of conversion.  Phantom stock earns dividends, also payable in phantom stock, which are recorded in each Director’s phantom account.  The value of these accounts is issued in stock or cash, at the election of the BOD, at the time the Director leaves the BOD.

            The annual retainer for non-employee directors is $120,000, and the minimum amount to be paid in NVE stock is $75,000 per director.  During 2009, 2008, and 2007, NVE granted the following total shares and related compensation to directors including NVE stock, respectively: 93,730, 72,573, and 27,300, shares, and $450,015, $396,309, and $280,000.

Common Stock Offering

In December 2007, NVE issued 12 million shares of its $1 par value common stock.  Net proceeds from the issuance were $202.8 million.  In December 2007, NVE contributed capital to NPC of approximately $65 million, and to SPPC of approximately $65 million.  Both Utilities used the proceeds to repay indebtedness under their revolving credit facilities, and for general corporate purposes.  Additionally, NVE contributed capital to NPC of approximately $146.6 million and to SPPC of approximately $20 million for general corporate purposes in 2008.

Common Stock Investment Plan

NVE offers a Common Stock Investment Plan (CSIP, or the Plan) for the purpose of promoting long-term ownership by providing a convenient method to purchase shares of our common stock and to reinvest cash dividends.  New investors can purchase common stock directly from the company for as little as $250 for the first purchase.  Existing shareholders can purchase additional

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shares up to once per month for as little as $50.  Shares are purchased on the first business day of each month with the exception of months in which a dividend is paid where purchases are scheduled to be made on the date of the dividend payment.  Through this Plan, shareholders can also choose to reinvest all or a portion (specified in increments of 10%) of cash dividends to purchase additional shares of common stock.

Dividends

	Dividends declared per share
	2009		2008
First Quarter	$	0.10	$	0.08
Second Quarter		0.10		0.08
Third Quarter		0.10		0.08
Fourth Quarter		0.11		0.10

On February 2, 2010, NVE’s BOD declared a quarterly cash dividend of $0.11 per share payable on March 17, 2010, to common shareholders of record on March 2, 2010.

During 2009 and 2008, NPC paid dividends to NVE of $112.0 million and $54.9 million, respectively.  During 2009 and 2008, SPPC paid dividends to NVE of $128.8 million and $141.5 million, respectively.

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NOTE 15.        EARNINGS PER SHARE (NVE)

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

The following table outlines the calculation for earnings per share (EPS):

	Year Ended December 31,
	2009		2008		2007
Basic EPS
Numerator ($000)
Net income	$	182,936	$	208,887	$	197,295
Denominator
Weighted average number of common shares outstanding		234,542,292		234,031,750		222,180,440
Per Share Amounts
Net income per share - basic	$	0.78	$	0.89	$	0.89
Diluted EPS
Numerator ($000)
Net income	$	182,936	$	208,887	$	197,295
Denominator(1)
Weighted average number of shares outstanding before dilution		234,542,292		234,031,750		222,180,440
Stock options		27,596		39,556		123,124
Non-Employee Director stock plan		100,244		63,636		46,551
Employee stock purchase plan		7,331		4,615		878
Restricted Shares		12,389		1,842		-
Performance Shares		490,836		443,605		203,031
		235,180,688		234,585,004		222,554,024
Per Share Amounts
Net income per share - diluted	$	0.78	$	0.89	$	0.89

(1)       The denominator does not include stock equivalents for all the options issued under the nonqualified stock option plan for the years ended December 31, 2009, 2008, and 2007, due to conversion prices being higher than market prices for all periods.  Under this plan, an additional 679,272, 943,231, and 638,250 shares, respectively, would be included in each of these periods if the conditions for conversions were met.

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NOTE 16.         ASSETS HELD FOR SALE

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

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

Assets	December 31, 2009		December 31, 2008
Utility Plant in Service	$	188.6	$	183.2
Less:  Accumulated depreciation		55.4		56.0
Utility Plant in Service, net		133.2		127.2
CWIP		4.6		5.5
Other current assets		8.6		6.8
Deferred Charges		0.8		3.0
Assets Held for Sale	$	147.2	$	142.5
Liabilities
Deferred Credits and Other Liabilities	$	25.7	$	24.1
Liabilities Held for Sale	$	25.7	$	24.1

NOTE 17.         SEVERANCE PROGRAMS

In response to reduced load growth and reductions in capital construction, NVE and the Utilities conducted reviews of their current operating costs to align future operating and maintenance expenses with forecasted load growth.  During 2009, NVE and the Utilities reduced their workforce by approximately 5% through a combination of voluntary and involuntary severance programs.

As a result of the severance programs, NVE, NPC and SPPC recorded other operating expense of approximately $197 thousand, $6.7 million, and $6.3 million, respectively, of estimated severance costs primarily for their management, professional administrative and technical (MPAT) class of employees in the fourth quarter 2009.  See Note 13, Pension and Other Post Retirement Benefits, for additional details regarding severance costs.  Management expects additional expense to be recognized in 2010 related to these programs; however, such amounts cannot be reasonably estimated at this time.

NOTE 18.         QUARTERLY FINANCIAL DATA (UNAUDITED)

The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods.  Dollars are presented in thousands except per share amounts.

In the past, the financial statements for NVE and the Utilities were presented in a traditional utility format; however, many utilities have partially or completely departed from the traditional utility format.  As a result, NVE and the Utilities elected to present current and prior period financial statements and related financial data in a similar commercial format and have reclassified prior year information to conform with the current period presentation.  The change in format did not have an effect on net income.

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	NVE
	2009 Quarter Ended
	March			June		September		December
Operating Revenues	$	755,267		$	838,641	$	1,219,007	$	772,883
Operating Income as previously reported(1)	$	55,753		$	90,215	$	261,305		N/A
Reclassification of Income Taxes	$	(13,656	)	$	4,084	$	80,780		N/A
Revised Operating Income	$	42,097		$	94,299	$	342,085	$	85,602
Net Income (Loss)	$	(22,244	)	$	18,383	$	182,646	$	4,151	(2)
Net Income (Loss) per Share
Basic & Diluted	$	(0.09	)	$	0.08	$	0.78	$	0.02

	2008 Quarter Ended
	March		June		September		December
Operating Revenues	$	805,051	$	838,794	$	1,118,131	$	766,137
Operating Income as previously reported(1)	$	76,813	$	94,201	$	218,952	$	85,362
Reclassification of Income Taxes	$	8,619	$	12,928	$	61,148	$	(5,944	)
Revised Operating Income	$	85,432	$	107,129	$	280,100	$	79,418
Net Income (Loss)	$	24,058	$	36,134	$	150,783	$	(2,088	)	(3)
Net Income (Loss) per Share
Basic & Diluted	$	0.10	$	0.15	$	0.64	$	(0.01	)

(1)	Amounts previously reported for operating income differ from amounts currently reported due to NVE’s decision to move from a Utility financial statement format which reports income taxes related to operating expenses as a component of operating income, to a commercial format which deducts income taxes after operating income. The change in format did not have an effect on Net Income.  See Note 1, Significant Accounting Policies, for further discussion on the change in financial statement format.
(2)	As discussed in Note 17, Severance Programs, NVE and the Utilities recorded expense related to severance programs of $13.2 million in the fourth quarter of 2009.
(3)	NVE experienced a Net Loss for the Quarter Ended December 31, 2008, primarily as a result of increased interest expense and depreciation.   Interest expense increased due to the issuance of new debt by the Utilities.  NPC issued a substantial amount of debt in 2008 primarily to fund the acquisition of the Higgins Generating Station and other major capital projects.  SPPC issued debt to fund the construction of the Tracy Generating Station.  Depreciation expense increased as a result of the acquisition of the Higgins Generating Station, which was not included in rates prior to July 1, 2009.

	NPC
	2009 Quarter Ended
	March			June		September		December
Operating Revenues	$	436,529		$	575,769	$	933,520	$	477,559
Operating Income as previously reported(1)	$	15,465		$	60,640	$	217,686		N/A
Reclassification of Income Taxes	$	(18,547	)	$	1,035	$	75,214		N/A
Revised Operating Income (Loss)	$	(3,082	)	$	61,675	$	292,900	$	44,869
Net Income (Loss)	$	(35,151	)	$	12,501	$	163,591	$	(6,657	)	(2)

162

	2008 Quarter Ended
	March		June		September		December
Operating Revenues	$	469,172	$	570,223	$	826,825	$	449,207
Operating Income as previously reported(1)	$	40,797	$	67,067	$	165,001	$	39,087
Reclassification of Income Taxes	$	2,132	$	12,865	$	54,595	$	(11,578	)
Revised Operating Income	$	42,929	$	79,932	$	219,596	$	27,509
Net Income (Loss)	$	7,971	$	33,175	$	124,336	$	(14,051	)	(3)

(1)	Amounts previously reported for operating income differ from amounts currently reported due to NVE’s decision to move from a Utility financial statement format which reports income taxes related to operating expenses as a component of operating income, to a commercial format which deducts income taxes after operating income. The change in format did not have an effect on Net Income.  See Note 1, Significant Accounting Policies, for further discussion on the change in financial statement format.
(2)	As discussed in Note 17, Severance Programs, NPC recorded expense related to severance programs of $6.7 million in the fourth quarter of 2009.
(3)	NPC experienced a Net Loss for the Quarter Ended December 31, 2008, primarily as a result of increased interest expense and depreciation.  Interest expense increased due to the issuance of new debt.  NPC issued a substantial amount of debt in 2008 primarily to fund the acquisition of the Higgins Generating Station and other major capital projects.  Depreciation expense increased as a result of the acquisition of the Higgins Generating Station, which was not included in rates prior to July 1, 2009.

	SPPC
	2009 Quarter Ended
	March		June		September		December
Operating Revenues	$	318,731	$	262,862	$	285,479	$	295,321
Operating Income as previously reported(1)	$	36,623	$	28,833	$	39,405		N/A
Reclassification of Income Taxes	$	9,078	$	4,752	$	10,445		N/A
Revised Operating Income	$	45,701	$	33,585	$	49,850	$	41,453
Net Income (Loss)	$	19,136	$	14,804	$	24,266	$	14,879	(2)

	2008 Quarter Ended
	March		June		September		December
Operating Revenues	$	335,872	$	268,567	$	291,298	$	316,924
Operating Income as previously reported(1)	$	33,969	$	24,539	$	50,108	$	45,537
Reclassification of Income Taxes	$	9,659	$	3,952	$	10,602	$	7,593
Revised Operating Income	$	43,628	$	28,491	$	60,710	$	53,130
Net Income (Loss)	$	24,284	$	10,849	$	32,919	$	22,530

(1)

Amounts previously reported for operating income differ from amounts currently reported due to NVE’s decision to move from a Utility financial statement format which reports income taxes related to operating expenses as a component of operating income, to a commercial format which deducts income taxes after operating income. The change in format did not have an effect on Net Income.  See Note 1, Significant Accounting Policies, for further discussion on the change in financial statement format.

(2)

As discussed in Note 17, Severance Programs, SPPC recorded expense related to severance programs of $6.3 million in the fourth quarter of 2009.

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ITEM 9A(T).                                CONTROLS AND PROCEDURES

   Nevada Power Company

The management of NPC is responsible for establishing and maintaining adequate internal control over financial reporting.  NPC’s internal control system was designed to provide reasonable assurance to the company’s management and BOD regarding the preparation and fair presentation of published financial statements.

Although NPC is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

NPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009.  In making this assessment, NPC used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  Based on our assessment we believe that, as of December 31, 2009, NVE’s internal control over financial reporting is effective based on those criteria.

   Sierra Pacific Power Company

The management of SPPC is responsible for establishing and maintaining adequate internal control over financial reporting.  SPPC’s internal control system was designed to provide reasonable assurance to the Company’s management and BOD regarding the preparation and fair presentation of published financial statements.

Although SPPC is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

SPPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009.  In making this assessment, SPPC used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway

164

Commission (COSO) in Internal Control-Integrated Framework.  Based on our assessment we believe that, as of December 31, 2009, NVE’s internal control over financial reporting is effective based on those criteria.

Attestation Report

This annual report does not include an attestation report of the independent registered public accountants regarding internal control over financial reporting of NPC and SPPC.  The management reports of NPC and SPPC were not subject to attestation by the independent registered public accountants pursuant to the rules of the SEC that permit NPC and SPPC to provide only management’s reports in their annual report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

NV Energy, Inc.

Las Vegas, Nevada

We have audited the internal control over financial reporting of NV Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2009, of the Company and our report dated February 22, 2010, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 22, 2010

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PART IV
ITEM 15.		EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements, Financial Statement Schedules and Exhibits
			Page
1.	Financial Statements
	NV Energy, Inc.:
	Consolidated Income Statements for the Years Ended December 31, 2009, 2008 and 2007		87
	Consolidated Balance Sheets as of December 31, 2009 and 2008		88
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		90
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		91
	Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007		92
	Nevada Power Company:
	Consolidated Income Statements for the Years Ended December 31, 2009, 2008 and 2007		93
	Consolidated Balance Sheets as of December 31, 2009 and 2008		94
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		96
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		97
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2009, 2008 and 2007		98
	Sierra Pacific Power Company:
	Consolidated Income Statements for the Years Ended December 31, 2009, 2008 and 2007		99
	Consolidated Balance Sheets as of December 31, 2009 and 2008		100
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		102
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		103
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2009, 2008 and 2007		104
Notes to Financial Statements for NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company			105
2.	Financial Statement Schedules:
		Schedule II - NV Energy, Inc. Consolidated Valuation and Qualifying Accounts	169
		Schedule II - Nevada Power Company Consolidated Valuation and Qualifying Accounts	169
		Schedule II - Sierra Pacific Power Company Consolidated Valuation and Qualifying Accounts	170
All other schedules have been omitted because they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.  Columns omitted from schedules have been omitted because the information is not applicable.
3.	Exhibits:
		Exhibits are listed in the Exhibit Index on pages 171 to 178.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company (both d/b/a NV Energy) have each duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.  The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	NV ENERGY, INC.
	NEVADA POWER COMPANY d/b/a NV ENERGY
	SIERRA PACIFIC POWER COMPANY d/b/a NV ENERGY
By	/s/ E. Kevin Bethel
	E. Kevin Bethel
	Chief Accounting Officer (Principal Accounting Officer)
	Interim Chief Financial Officer (Principal Financial Officer)
	February 25, 2010

168

NV Energy, Inc.
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2009, 2008 and 2007
(Dollars in Thousands)
	Provision for Uncollectible Accounts
Balance at January 1, 2007	$	39,571
Provision charged to income		10,495
Amounts written off, less recoveries		(13,921	)
Balance at December 31, 2007	$	36,145
Balance at January 1, 2008	$	36,145
Provision charged to income		16,686
Amounts written off, less recoveries		(19,947	)
Balance at December 31, 2008	$	32,884
Balance at January 1, 2009	$	32,884
Provision charged to income		21,839
Amounts written off, less recoveries		(22,382	)
Balance at December 31, 2009	$	32,341

Nevada Power Company
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2009, 2008 and 2007
(Dollars in Thousands)
	Provision for Uncollectible Accounts
Balance at January 1, 2007	$	32,834
Provision charged to income		9,269
Amounts written off, less recoveries		(11,711	)
Balance at December 31, 2007	$	30,392
Balance at January 1, 2008	$	30,392
Provision charged to income		16,858
Amounts written off, less recoveries		(16,629	)
Balance at December 31, 2008	$	30,621
Balance at January 1, 2009	$	30,621
Provision charged to income		17,519
Amounts written off, less recoveries		(18,765	)
Balance at December 31, 2009	$	29,375

169

Sierra Pacific Power Company
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2009, 2008 and 2007
(Dollars in Thousands)
	Provision for Uncollectible Accounts
Balance at January 1, 2007	$	6,737
Provision charged to income		1,226
Amounts written off, less recoveries		( 2,210	)
Balance at December 31, 2007	$	5,753
Balance at January 1, 2008	$	5,753
Provision charged to income		(173	)
Amounts written off, less recoveries		(3,318	)
Balance at December 31, 2008	$	2,262
Balance at January 1, 2009	$	2,262
Provision charged to income		4,321
Amounts written off, less recoveries		(3,617	)
Balance at December 31, 2009	$	2,966

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2009 FORM 10-K EXHIBIT INDEX

(a)  Exhibits Index

Certain of the following exhibits with respect to NV Energy, Inc. and its subsidiaries, Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, Lands of Sierra, Inc., Sierra Pacific Energy Company and Sierra Water Development Company, are filed herewith.  Certain other of such exhibits have heretofore been filed with the SEC and are incorporated herein by reference.

(* filed herewith)

(3)  NV Energy, Inc.

· Restated Articles of Incorporation of NV Energy, Inc. effective December 23, 2008, as amended (filed as Exhibit 3.1 to Form 10-Q for the quarter ended March 31, 2009).

· By-laws of NV Energy, Inc., as amended through May 1, 2009, (filed as Exhibit 3.2 to Form 10-Q for the quarter ended March 31, 2009).

Nevada Power Company

· Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999 (filed as Exhibit 3(B) to Form 10-K for year ended December 31, 1999).

· Amended and Restated By-Laws of Nevada Power Company dated July 28, 1999 (filed as Exhibit 3(C) to Form 10-K for year ended December 31, 1999).

Sierra Pacific Power Company

· Restated Articles of Incorporation of Sierra Pacific Power Company dated October 25, 2006 (filed as Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2006).

· By-laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996).

(4)   NV Energy, Inc.

· Indenture between NV Energy, Inc. (under its former name, Sierra Pacific Resources) and The Bank of New York, dated May 1, 2000, for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May 22, 2000).

· Agreement of Resignation, Appointment and Acceptance dated November 6, 2009 by and among NV Energy, Inc., The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.1 to Form 10-K for the year ended December 31, 2009).

· Officers’ Certificate dated August 12, 2005, establishing the terms of NV Energy, Inc.’s (under its former name, Sierra Pacific Resources) 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005).

· Form of NV Energy, Inc.’s (under its former name, Sierra Pacific Resources) 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005).

· Officers’ Certificate dated June 14, 2005, establishing the terms of NV Energy, Inc.’s (under its former name, Sierra Pacific Resources) 7.803% Senior Notes due 2012 (filed as Exhibit 99.1 to Form 8-K dated June 16, 2005).

· Indenture, dated March 19, 2004, between NV Energy, Inc. (under its former name, Sierra Pacific Resources) and the Bank of New York, as Trustee, in connection with the issuance of 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004).

· Form of NV Energy, Inc.’s (under its former name, Sierra Pacific Resources) 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004).

171

Nevada Power Company

· General and Refunding Mortgage Indenture, dated May 1, 2001, between Nevada Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.1(a) to Form 10-Q for the quarter ended June 30, 2001).

· Agreement of Resignation, Appointment and Acceptance dated November 6, 2009 by and among Nevada Power Company d/b/a NV Energy, The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.2 to Form 10-K for the year ended December 31, 2009).

· First Supplemental Indenture, dated as of May 1, 2001, establishing Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(b) to Form 10-Q for the quarter ended June 30, 2001).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.l(c) to Form 10-Q for the quarter ended June 30, 2001).

· Form of Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(d) to Form 10-Q for the quarter ended June 30, 2001).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I, due 2012 (filed as Exhibit 4.1 to Form 10-Q for quarter ended June 30, 2004).

· Form of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I due 2012 (filed as Exhibit 4.2 to Form 10-Q for quarter ended June 30, 2004).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(A) to Form 10-K filed for year ended December 31, 2005).

· Form of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(B) to Form 10-K filed for year ended December 31, 2005).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2005).

· Form of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(B) to Form 10-K for the year ended December 31, 2005).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006.

· Form of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Appendix A to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Exhibit 4.7 to Form S-4 filed June 7, 2006).

· Form of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Appendix A to Exhibit 4.7 to Form S-4 filed June 7, 2006).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.750% General and Refunding Mortgage Notes, Series R, due 2037 (filed as Exhibit 4.1 to Form 8-K dated June 27, 2007).

· Form of Nevada Power Company’s 6.750% General and Refunding Mortgage Notes, Series R, due 2037 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated June 27, 2007).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series S, due 2018 (filed as Exhibit 4.1 to Form 8-K dated July 28, 2008).

· Form of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series S, due 2018 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated July 28, 2008).

· Officer’s Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 7.375% General and Refunding Mortgage Notes, Series U, due 2014 (filed as Exhibit 4.1 to Form 8-K dated January 8, 2009).

172

· Form of Nevada Power Company d/b/a NV Energy’s 7.375% General and Refunding Mortgage Notes, Series U, due 2014 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated January 8, 2009).

· Officer's Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 7.125% General and Refunding Mortgage Notes, Series V, due 2019 (filed as Exhibit 4.1 to Form 8-K dated February 25, 2009).

· Form of Nevada Power Company d/b/a NV Energy’s 7.125% General and Refunding Mortgage Notes, Series V, due 2019 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated February 25, 2009).

Sierra Pacific Power Company

· General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York as Trustee (filed as Exhibit 4.2(a) to Form 10-Q for the quarter ended June 30, 2001).

· Second Supplemental Indenture, dated as of October 30, 2006, to subject additional properties of Sierra Pacific Power Company located in the State of California to the lien of the General and Refunding Mortgage Indenture and to correct defects in the original Indenture (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2006).

· Agreement of Resignation, Appointment and Acceptance dated November 6, 2009 by and among Sierra Pacific Power Company d/b/a NV Energy, The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.3 to Form 10-K for the year ended December 31, 2009).

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2004).

· Form of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.5 to Form 10-Q for the quarter ended March 31, 2004).

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006).

· Form of First Supplemental Officer's Certificate establishing the terms of Sierra Pacific Power Company's 6% General and Refunding Mortgage Notes, Series M, Due 2016 (filed as Exhibit 4.2 to Form 8-K dated August 18, 2009).

· Form of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Appendix A to Exhibit 4.2 to Form 8-K dated August 18, 2009.

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6.750% General and Refunding Mortgage Notes, Series P, due 2037 (filed as Exhibit 4.2 to Form 8-K dated June 27, 2007).

· Form of Sierra Pacific Power Company’s 6.750% General and Refunding Mortgage Notes, Series P, due 2037 (filed as Appendix A to Exhibit 4.2 to Form 8-K dated June 27, 2007).

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 (filed as Exhibit 4.1 to Form 8-K dated August 28, 2008)

· Form of Sierra Pacific Power Company’s 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated August 28, 2008).

(10)   NV Energy, Inc.

· Written description of employment arrangement for Jeffrey L. Ceccarelli (filed as Exhibit 10(C) to Form 10-K for year ended December 31, 2007).

· Employment Letter dated May 9, 2007 for Michael W. Yackira (filed as Exhibit 10(D) to Form 10-K for year ended December 31, 2007).

· Paul J. Kaleta Employment Letter dated January 9, 2006 (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2005).

173

· Roberto Denis Employment Letter dated July 11, 2003 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2003).

· NV Energy, Inc. (under its former name, Sierra Pacific Resources) Executive Change of Control Policy, effective January 1, 2008 (filed as Exhibit 10.1 to Form 10-K for the year ended December 31, 2008).

· NV Energy, Inc. (under its former name, Sierra Pacific Resources) Amended and Restated 2004 Executive Long-Term Incentive Plan (filed as Appendix A to 2008 Proxy Statement).

· NV Energy, Inc. (under its former name, Sierra Pacific Resources) 2003 Non-Employee Director Stock Plan, as amended (filed as Exhibit 99.2 to Form S-8 dated October 19, 2007).

· NV Energy, Inc. Amended and Restated Employee Stock Purchase Plan (filed as Exhibit 10.1 to Form 10-K for the year ended December 31, 2009).

· Separation Agreement dated February 17, 2010, between NV Energy, Inc. and William D. Rogers (filed as Exhibit 10.2 to Form 10-K for the year ended December 31, 2009).

Nevada Power Company

· Collective Bargaining Agreement dated as of February 1, 2008, effective through February 1, 2011, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396 (filed as Exhibit 10.2 to Form 10-K for the year ended December 31, 2008).

· Asset Purchase Agreement dated April 21, 2008, between Reliant Energy Wholesale Generation, LLC, Reliant Energy Asset Management, LLC and Nevada Power Company (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2008).

· Joint Tenant Contract, dated September 18, 2007, between Nevada Power Company as Tenant, and Beltway Business Park Warehouse No. 2, LLC as Owner, relating to Nevada Power Company’s South Operations Center facility (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2007).

· Lease, dated December 11, 2006, between Nevada Power Company as lessee and Beltway Business Park Warehouse No. 2, LLC as lessor, relating to Nevada Power Company’s South Operations Center facility (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2006).

· Second Amended and Restated Credit Agreement, dated as of November 4, 2005, among Nevada Power Company, Wachovia Bank, as administrative agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2005).

· Amendment and Consent, dated April 19, 2006, to the Second Amended and Restated Credit Agreement, dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2006).

· Second Amendment, dated November 25, 2008, to the Second Amended and Restated Credit Agreement, dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2009).

· Third Amendment, dated December 11, 2008, to the Second Amended and Restated Credit Agreement dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.3 to Form 10-QK for the year ended December 31, 2008).

· Fourth Amendment, dated February 10, 2009, to the Second Amended and Restated Credit Agreement dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2009).

· Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona $13,000,000 Pollution Control Corporation Refunding Revenue Bonds Series 2006B) (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2006).

· Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona $40,000,000 Pollution Control Corporation Refunding Revenue Bonds, Series 2006A) (filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2006).

· Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company, dated June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2000).

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· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A) (filed as Exhibit 10.75 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995CB) (filed as Exhibit 10.76 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A and $44,000,000 Industrial Development Refunding Revenue Bonds, Series 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-1698, for the year ended December 31, 1995).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds, Series 1995D) (filed as Exhibit 10.78 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

· Participation Agreement Reid Gardner Unit No. 4 dated July 11, 1979 between Nevada Power Company and California Department of Water Resources (filed as Exhibit 5.34 to Form S-7, File No. 2-65097).

· Amended Mohave Project Coal Slurry Pipeline Agreement dated May 26, 1976 between Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) (filed as Exhibit 5.36 to Form S-7, File No. 2-56356).

· Navajo Project Co-Tenancy Agreement dated March 23, 1976 between Nevada Power Company, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the United States of America (filed as Exhibit 5.31 to Form 8-K, File No. 1-4696, April 1974).

· Mohave Operating Agreement dated July 6, 1970 between Nevada Power Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Department of Water and Power of the City of Los Angeles (filed as Exhibit 13.26F to Form S-1, File No. 2-38314).

· Eldorado System Conveyance and Co-Tenancy Agreement dated December 20, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.30 to Form S-9, File No. 2-28348).

· Mohave Project Plant Site Conveyance and Co-Tenancy Agreement dated May 29, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.27 to Form S-9, File No. 2-28348).

· Settlement Agreement dated December 19, 2003, between Nevada Power Company, Pinnacle West Energy Corporation and Southern Nevada Water Authority (filed as Exhibit 10(G) to Form 10-K for the year ended December 31, 2003).

· Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company as lessee, dated January 1, 1984 for lease of administrative headquarters (the primary term of the sublease ends in 2014 and the lessee has the option to extend the term up to 25 additional years)(filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, for the year ended December 31, 1983).

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Sierra Pacific Power Company

· Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007A) (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2007).

· Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007B) (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2007).

· Collective Agreement, amended as of March 5, 2007, between Sierra Pacific Power Company and Local Union 1245 of the International Brotherhood of Electrical Workers (filed as Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2007)

· Amended and Restated Credit Agreement, dated as of November 4, 2005 among Sierra Pacific Power Company, Wachovia Bank, National Association, as administrative agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2005).

· Amendment and Consent, dated April 19, 2006, to the Amended and Restated Credit Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2006).

· Second Amendment, dated November 25, 2008, to the Amended and Restated Credit Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2009).

· Third Amendment, dated February 10, 2009, to the Amended and Restated Credit Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.4 to Form 10-Q for the quarter ended March 31, 2009).

· Financing Agreement dated November 1, 2006 between Humboldt County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Humboldt County, Nevada $49,750,000 Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006) (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2006).

· Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $58,750,000 Gas Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A) (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 2006).

· Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $75,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B) (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 2006).

· Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $84,800,000 Gas and Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C) (filed as Exhibit 10(E) to Form 10-K for the year ended December 31, 2006).

· Settlement Agreement and Mutual Release dated May 8, 1992 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the Securities and Exchange Commission).

· Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company’s corporate headquarters building (filed as Exhibit (10)(I) to Form 10-K for the year ended December 31, 1992).

· Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the company’s corporate headquarters building (filed as Exhibit (10)(K) to Form 10-K for the year ended December 31, 1993).

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 (11)  Nevada Power Company and Sierra Pacific Power Company

· Nevada Power Company and Sierra Pacific Power Company are wholly owned subsidiaries and, in accordance with the accounting guidance for earnings per share as reflected in the Earnings Per Share Topic of the FASC, earnings per share data have been omitted.

(12)  NV Energy, Inc.

· Statement regarding computation of Ratios of Earnings to Fixed Charges (filed as Exhibit 12.1 to Form 10-K for the year ended December 31, 2009).

        Nevada Power Company

· Statement regarding computation of Ratios of Earnings to Fixed Charges (filed as Exhibit 12.2 to Form 10-K for the year ended December 31, 2009).

        Sierra Pacific Power Company

· Statement regarding computation of Ratios of Earnings to Fixed Charges (filed as Exhibit 12.3 to Form 10-K for the year ended December 31, 2009).

(21)  NV Energy, Inc.

· Nevada Power Company d/b/a NV Energy, a Nevada Corporation.

                   Sierra Pacific Power Company d/b/a NV Energy, a Nevada Corporation.

                   Great Basin Energy Company, a Nevada Corporation.

                   Lands of Sierra Inc., a Nevada Corporation.

                   Sierra Energy Company dba e-three, a Nevada Corporation.

                   Sierra Gas Holdings Company, a Nevada Corporation.

                   Sierra Pacific Energy Company, a Nevada Corporation.

                   Sierra Water Development Company, a Nevada Corporation.

        Sierra Pacific Communications, a Nevada Corporation

        NVE Insurance Company, Inc., a Nevada Corporation

Nevada Power Company

· Nevada Electric Investment Company, a Nevada Corporation.

                   Commonsite, Inc., a Nevada Corporation.

Sierra Pacific Power Company

· Piñon Pine Company, a Nevada Corporation.

                    Piñon Pine Investment Company, a Nevada Corporation.

                    Piñon Pine Investment Co. LLC, a Nevada Limited Liability Company.

                    GPSF-B, a DelawareCorporation.

                    SPPC Funding LLC, a Delaware Limited Liability Company.

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

· *(23.1) Consent of Independent Registered Public Accounting Firm in connection with NV Energy, Inc.’s Registration Statements No. 333-145686 on Form S-3D, Registration Statements No. 333-92651 and No. 333-146822 on Form S-8, and Registration Statement No. 333-146100 on Form S-3ASR.

· *(23.2) Consent of Independent Registered Public Accounting Firm in connection with Nevada Power Company’s Registration Statement No. 333-146100-02 on Form S-3ASR.

· *(23.3) Consent of Independent Registered Public Accounting Firm in connection with Sierra Pacific Power Company’s Registration Statement No. 333-146100-01 on Form S-3ASR.

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

· *(31.1) Annual Certification of Chief Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.2) Annual Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.3) Annual Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.4) Annual Certification of Chief Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.5) Annual Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.6) Annual Certification of Chief 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 Chief Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.2) Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.3) Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.4) Certification of Chief Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.5) Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.6) Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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