Sierra Pacific Power 10K/A 2007 Annual report (amended)

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, 2007


	Registrant, Address of	I.R.S.
Commission	Principal Executive Offices	Employer
File	and Telephone	Identification	State of
Number	Number	Number	Incorporation
1-08788	SIERRA PACIFIC RESOURCES	88-0198358	Nevada
	P.O. Box 30150 (6100 Neil Road)
	Reno, Nevada 89520-3150 (89511)
	(775) 834-4011

2-28348	NEVADA POWER COMPANY	88-0420104	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 367-5000

0-00508	SIERRA PACIFIC POWER COMPANY	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 Sierra Pacific Resources:
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:

Sierra Pacific Resources 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 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. Yesþ Noo

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 the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Sierra Pacific Resources:


Large accelerated filerþ		Accelerated filero		Non-accelerated filero (Do not check if a smaller reporting company)		Smaller reporting companyo

Nevada Power Company:


Large accelerated filero		Accelerated filero		Non-accelerated filerþ (Do not check if a smaller reporting company)		Smaller reporting companyo

Sierra Pacific Power Company:


Large accelerated filero		Accelerated filero		Non-accelerated filerþ (Do not check if a smaller reporting company)		Smaller reporting companyo

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 Sierra Pacific Resources’ common stock held by non-affiliates. As of June 30, 2007: $ 3,891,381,447

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 Sierra Pacific Resources outstanding at February 22, 2008: 233,889,221 Shares

Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.

Sierra Pacific Resources 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 Sierra Pacific Resources’ definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held April 28, 2008, are incorporated by reference into Part III hereof.

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

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A (the “Form 10-K/A”) amends our annual report for the fiscal year ended December 31, 2007, originally filed with the Securities and Exchange Commission (“SEC”) on February 27, 2008 (the “Form 10-K”). We are filing this Form 10-K/A to correct printer errors made in (A) “Item 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA” regarding (i) the date of the REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM to the Board of Directors and Shareholders of Sierra Pacific Resources, which was erroneously dated “February 26, 2008” and has been changed to “February 27, 2008” to reflect the proper date of the report, (ii) the date of the REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM to the Board of Directors and Shareholder of Nevada Power Company, which was erroneously dated “February 26, 2008” and has been changed to “February 27, 2008” to reflect the proper date of the report, (iii) the date of the REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM to the Board of Directors and Shareholder of Sierra Pacific Power Company, which was erroneously dated “February 26, 2008” and has been changed to “February 27, 2008” to reflect the proper date of the report, and (iv) the failure to delete the following sentence from Note 11: “The asset values are determined using quoted market prices”, which is the third sentence after the table entitled “Change in plan assets” on page 142 of the Form 10-K and is now properly deleted; (B) “Item 9A(T) — CONTROLS AND PROCEDURES” regarding the date of the REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM to the Board of Directors and Shareholders of Sierra Pacific Resources, which was erroneously dated “February 26, 2008” and has been changed to “February 27, 2008” to reflect the proper date of the report; and (C) “Item 15—EXHIBITS AND FINANCIAL STATEMENT SCHEDULES” to correct the date of the CONSENT OF INDEPENDENT ACCOUNTING FIRM for each of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company filed respectively as Exhibit 23(A), Exhibit 23(B) and Exhibit 23(C) to the Form 10-K, which were erroneously dated “February 26, 2008” and have been changed to “February 27, 2008” to reflect the proper date of the reports.

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		86

Financial Statements:

Sierra Pacific Resources:
Consolidated Balance Sheets as of December 31, 2007 and 2006		89
Consolidated Income Statements for the Years Ended December 31, 2007, 2006 and 2005		90
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005		91
Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005		92
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		93
Consolidated Statements of Capitalization as of December 31, 2007 and 2006
		94

Nevada Power Company:
Consolidated Balance Sheets as of December 31, 2007 and 2006		96
Consolidated Income Statements for the Years Ended December 31, 2007, 2006 and 2005		97
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005		98
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2007, 2006 and 2005		99
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		100
Consolidated Statements of Capitalization as of December 31, 2007 and 2006		101

Sierra Pacific Power Company:
Consolidated Balance Sheets as of December 31, 2007 and 2006		102
Consolidated Income Statements for the Years Ended December 31, 2007, 2006 and 2005		103
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005		104
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2007, 2006 and 2005		105
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		106
Consolidated Statements of Capitalization as of December 31, 2007 and 2006		107

Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company		108

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Sierra Pacific Resources
Reno, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Resources and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated income statements and statements of comprehensive income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15(a) (2). These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Resources and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, on January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R).

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, 2007, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Reno, Nevada
February 27, 2008

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 and statements of capitalization of Nevada Power Company and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated income statements, statements of comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a) (2). 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, 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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, present fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Reno, Nevada
February 27, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Reno, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Power Company and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated income statements and statements of comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a) (2). 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.

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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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, present fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Reno, Nevada
February 27, 2008

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


	December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	8,468,711	$	7,954,337
Less accumulated provision for depreciation		2,526,379		2,333,357

		5,942,332		5,620,980
Construction work-in-progress		1,068,666		466,018

		7,010,998		6,086,998

Investments and other property, net (Note 4)		31,061		34,325


Current Assets:
Cash and cash equivalents		129,140		115,709
Accounts receivable less allowance for uncollectible accounts:
2007-$36,061; 2006-$39,566		434,359		415,082
Deferred energy costs — electric (Note 1)		75,948		168,260
Materials, supplies and fuel, at average cost		117,483		103,757
Risk management assets (Note 9)		22,286		27,305
Deferred income taxes (Note 10)		43,295		55,546
Deposits and prepayments for energy		1,142		15,968
Other		44,767		31,580

		868,420		933,207


Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		205,030		382,286
Regulatory tax asset (Note 10)		267,848		263,170
Regulatory asset for pension plans (Note 11)		133,984		223,218
Other regulatory assets (Note 1)		758,287		668,624
Risk management assets (Note 9)		12,429		7,586
Risk management regulatory assets — net (Note 9)		26,067		122,911
Unamortized debt issuance costs		65,218		67,106
Other		85,408		42,645

		1,554,271		1,777,546

TOTAL ASSETS	$	9,464,750	$	8,832,076

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	2,996,575	$	2,622,297
Long-term debt		4,137,864		4,001,542

		7,134,439		6,623,839


Current Liabilities:
Current maturities of long-term debt		110,285		8,348
Accounts payable		357,867		282,463
Accrued interest		69,485		56,426
Accrued salaries and benefits		35,020		33,146
Current income taxes payable (Note 10)		3,544		5,914
Risk management liabilities (Note 9)		39,509		123,065
Accrued taxes		8,336		6,290
Deferred energy costs-electric (Note 1)		17,573		—
Deferred energy costs — gas (Note 1)		11,369		112
Other current liabilities		65,991		60,310

		718,979		576,074


Commitments and Contingencies (Note 13)

Deferred Credits and Other Liabilities:
Deferred income taxes (Note 10)		852,630		791,428
Deferred investment tax credit		28,895		35,218
Regulatory tax liability (Note 10)		28,445		34,075
Customer advances for construction		100,125		91,895
Accrued retirement benefits		77,525		226,420
Risk Management Liabilities (Note 9)		7,369		10,746
Regulatory liabilities		304,026		301,903
Other		212,317		140,478

		1,611,332		1,632,163

TOTAL CAPITALIZATION AND LIABILITIES	$	9,464,750	$	8,832,076

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)


	Year ended December 31,
	2007			2006			2005
OPERATING REVENUES:
Electric	$	3,395,487		$	3,144,243		$	2,850,694
Gas		205,430			210,068			178,270
Other		43			1,639			1,278

		3,600,960			3,355,950			3,030,242


OPERATING EXPENSES:
Operation:
Purchased power		1,036,905			1,109,440			1,315,986
Fuel for power generation		837,355			800,585			510,736
Gas purchased for resale		150,879			160,739			140,850
Deferred energy costs disallowed		14,171			—			—
Deferral of energy costs — electric - - net		297,039			139,365			(37,558	)
Deferral of energy costs — gas — net		10,763			6,947			(749	)
Reinstatement of deferred energy (Note 3)		—			(178,825	)		—
Other		379,446			367,198			363,802
Maintenance		99,035			93,172			78,730
Depreciation and amortization		235,532			228,875			214,662
Taxes:
Income taxes (Note 10)		75,155			91,571			39,185
Other than income		50,113			48,086			45,920

		3,186,393			2,867,153			2,671,564

OPERATING INCOME		414,567			488,797			358,678

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		31,809			18,226			20,322
Interest accrued on deferred energy		15,078			27,898			27,442
Early debt conversion fees		—			—			(54,000	)
Carrying charge for Lenzie (Note 1)		16,080			33,440			—
Gain on sale of investment		1,369			62,927			—
Reinstated interest on deferred energy (Note 3)		11,076			—			—
Other income		24,580			37,123			41,200
Other expense		(25,076	)		(23,497	)		(18,645	)
Income taxes (Note 10)		(12,400	)		(54,034	)		(3,933	)

		62,516			102,083			12,386

Total Income Before Interest Charges		477,083			590,880			371,064

INTEREST CHARGES:
Long-term debt		273,985			294,488			302,668
Interest for Energy Suppliers (Note 13)		—			—			(17,221	)
Other		31,770			33,719			24,171
Allowance for borrowed funds used during construction		(25,967	)		(17,119	)		(24,691	)

		279,788			311,088			284,927


Preferred stock dividend requirements of subsidiary and premium on redemption		—			2,341			3,900

NET INCOME APPLICABLE TO COMMON STOCK	$	197,295		$	277,451		$	82,237

Amount per share basic and diluted - (Note 15)
Net Income applicable to common stock	$	0.89		$	1.33		$	0.44

Weighted Average Shares of Common Stock Outstanding — basic		222,180,440			208,531,134			185,548,314

Weighted Average Shares of Common Stock Outstanding — diluted		222,554,024			209,020,896			185,932,504

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

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year ended December 31,
	2007			2006		2005
NET INCOME APPLICABLE TO COMMON STOCK	$	197,295		$	277,451	$	82,237

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $1,155 in 2005)		—			—		(2,146	)

Minimum pension liability adjustment (net of taxes of ($1,132) and $1,569 in 2006 and 2005, respectively)		—			2,106		(4,311	)
Change in SFAS 158 liability and amortization (net of taxes $1,250)		(2,323	)		—		—

OTHER COMPREHENSIVE INCOME (LOSS)		(2,323	)		2,106		(6,457	)

COMPREHENSIVE INCOME	$	194,972		$	279,557	$	75,780

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)


	Year ended December 31,
	2007			2006			2005
Common Stock:
Balance at Beginning of Year	$	221,030		$	200,792		$	117,469
Stock issuance/exchange, CSIP, DRP, ESPP and other		12,709			20,238			83,323

Balance at end of year		233,739			221,030			200,792


Other Paid-In Capital:
Balance at Beginning of Year		2,483,244			2,220,896			1,818,453
Premium on issuance/exchange of common stock		190,808			260,600			405,767
Common Stock issuance costs		(298	)		(857	)		(6,486	)
Revaluation of investment		—			—			119
Stock purchase and dividend reinvestment		504			—			—
Tax Benefit from stock option exercises		891			—			—
CSIP, DRP, ESPP and other		9,696			2,605			3,043

Balance at End of Year		2,684,845			2,483,244			2,220,896


Retained Earnings (Deficit):
Balance at Beginning of Year		(78,432	)		(355,883	)		(438,112	)
FIN 48 Adjustment to beginning balance		487			—			—
Net Income applicable to Common Stock		197,295			277,451			82,237
Common stock dividends declared, net of adjustments		(35,491	)		—			(8	)

Balance at End of Year		83,859			(78,432	)		(355,883	)


Accumulated Other Comprehensive Income (Loss):

Balance at Beginning of Year		(3,545	)		(5,651	)		806
Change in market value of risk management assets and liabilities as of
December 31 (Net of taxes of $1,155 in 2005 )		—			—			(2,146	)

Minimum pension liability adjustment (net of taxes of ($1,132) and $1,569 in 2006 and 2005, respectively)		—			2,106			(4,311	)
Change in SFAS 158 liability and amortization (net of taxes $1,250)		(2,323	)		—			—

Balance at End of Year		(5,868	)		(3,545	)		(5,651	)


Total Common Shareholders’ Equity at End of Year	$	2,996,575		$	2,622,297		$	2,060,154

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)


	Year Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income applicable to common stock	$	197,295		$	277,451		$	82,237
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		235,532			228,875			214,662
Deferred taxes and deferred investment tax credit		79,337			136,026			41,609
AFUDC		(31,809	)		(18,226	)		(45,013	)
Amortization of deferred energy costs - electric		246,907			166,821			188,221
Amortization of deferred energy costs — gas		701			6,234			1,446
Deferral of energy costs — electric		51,311			(54,737	)		(241,103	)
Deferral of energy costs — gas		10,668			436			(2,519	)
Deferral of energy costs — terminated suppliers		—			8,741			218,040
Reinstatement of deferred energy		—			(178,825	)		—
Carrying charge on Lenzie plant		(16,080	)		(33,440	)		—
Reinstated interest on deferred energy		(11,076	)		—			—
Gain on sale of investment		(1,369	)		(62,927	)		—
Other, net		23,679			24,650			(219	)
Changes in certain assets and liabilities:
Accounts receivable		(19,276	)		(43,214	)		(92,452	)
Materials, supplies and fuel		(13,725	)		(15,312	)		(12,251	)
Other current assets		1,639			24,050			20,663
Accounts payable		42,958			(2,739	)		55,985
Payment to terminating supplier		—			(65,368	)		—
Proceeds from claim on terminating supplier		—			41,365			—
Accrued retirement benefits		(75,820	)		(3,393	)		9,338
Other current liabilities		22,475			2,356			(162,416	)
Risk Management assets and liabilities		10,088			(5,950	)		(6,685	)
Other assets		2,498			(10,122	)		(9,950	)
Other liabilities		(2,112	)		6,690			(24,997	)

Net Cash from by Operating Activities		753,821			429,442			234,596


CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(1,197,326	)		(986,019	)		(686,394	)
AFUDC		31,809			18,226			45,013
Customer advances for construction		8,230			17,348			27,358
Contributions in aid of construction		32,165			38,792			23,351
Proceeds from sale of investment		1,935			99,730			—
Investments and other property — net		2,810			8,423			10,200

Net Cash used by Investing Activities		(1,120,377	)		(803,500	)		(580,472	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		—			3,612			23,711
Proceeds from issuance of long-term debt		1,246,383			2,491,883			370,211
Retirement of long-term debt		(1,044,866	)		(2,407,745	)		(373,938	)
Redemption of preferred stock		—			(51,366	)		—
Sale of Common Stock		213,339			281,554			235,618
Proceeds from exercise of stock option		548			1,040			590
Dividends paid		(35,417	)		(1,945	)		(3,911	)

Net Cash from Financing Activities		379,987			317,033			252,281


Net Increase (Decrease) in Cash and Cash Equivalents		13,431			(57,025	)		(93,595	)
Beginning Balance in Cash and Cash Equivalents		115,709			172,734			266,330

Ending Balance in Cash and Cash Equivalents	$	129,140		$	115,709		$	172,735


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	267,082		$	338,665		$	330,889
Income taxes	$	9,727		$	4,726		$	—

Noncash Activities:
Exchange of Convertible Debt for SPR Common Stock	$	—		$	—		$	248,168

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)


	December 31,
	2007			2006
Common Shareholders’ Equity:
Common stock, $1.00 par value, authorized 350 million; issued and outstanding 2007:233,739,000 shares; issued and outstanding 2006: 221,030,000 shares issued and outstanding	$	233,739		$	221,030
Other paid-in capital		2,684,845			2,483,244
Retained Earnings (Deficit)		83,859			(78,432	)
Accumulated other comprehensive loss		(5,868	)		(3,545	)

Total Common Shareholders’ Equity		2,996,575			2,622,297


Long-Term Debt:
Secured Debt
Debt Secured by General and Refunding Mortgage Indenture
Nevada Power Company
8.25% NPC Series A due 2011		350,000			350,000
6.50% NPC Series I due 2012		130,000			130,000
9.00% NPC Series G due 2013		17,244			227,500
5.875% NPC Series L due 2015		250,000			250,000
5.95% NPC Series M due 2016		210,000			210,000
6.65% NPC Series N due 2036		370,000			370,000
6.00% NPC Series O due 2018		325,000			325,000
6.75% NPC Series R due 2037		350,000			—

Subtotal		2,002,244			1,862,500

Sierra Pacific Power Company
8.00% SPPC Series A due 2008		99,243			320,000
6.25% SPPC Series H due 2012		100,000			100,000
6.00% SPPC Series M due 2016		300,000			300,000
5.00% SPPC Series 2001 due 2036		—			80,000
6.75% SPPC Series P due 2037		325,000			—

Subtotal		824,243			800,000

Variable Rate Notes
Nevada Power Company
NPC PCRB Series 2000B due 2009		15,000			15,000
NPC IDRB Series 2000A due 2020		100,000			100,000
NPC PCRB Series 2006 due 2036		39,500			39,500
NPC PCRB Series 2006A due 2032		40,000			40,000
NPC PCRB Series 2006B due 2039		13,000			13,000

Subtotal		207,500			207,500

Sierra Pacific Power Company
SPPC PCRB Series 2006 due 2029		49,750			49,750
SPPC PCRB Series 2006A due 2031		58,700			58,700
SPPC PCRB Series 2006B due 2036		75,000			75,000
SPPC PCRB Series 2006C due 2036		84,800			84,800
SPPC WFRB Series 2007A due 2036		40,000			—
SPPC WFRB Series 2007B due 2036		40,000			—

Subtotal		348,250			268,250

Unsecured Debt
Revenue Bonds
Nevada Power Company
5.30% NPC Series 1995D due 2011		14,000			14,000
5.45% NPC Series 1995D due 2023		6,300			6,300
5.50% NPC Series 1995C due 2030		44,000			44,000
5.60% NPC Series 1995A due 2030		76,750			76,750
5.90% NPC Series 1995B due 2030		85,000			85,000
5.90% NPC Series 1997A due 2032		52,285			52,285

Subtotal		278,335			278,335

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

(continued)

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)


	December 31,
	2007			2006
Other Notes
Sierra Pacific Resources
7.803% SPR Senior Notes due 2012		63,670			74,170
8.625% SPR Notes due 2014		250,039			250,039
6.75% SPR Senior Notes due 2017		210,500			225,000

Subtotal, excluding current portion		524,209			549,209


Unamortized bond premium and discount, net		(1,068	)		(11,813	)
Obligations under capital leases		61,424			50,479
Current maturities and sinking fund requirements		(110,285	)		(8,348	)
Other, excluding current portion		3,012			5,430

Total Long-Term Debt		4,137,864			4,001,542

TOTAL CAPITALIZATION	$	7,134,439		$	6,623,839

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

(Concluded)

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


	December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	5,571,492	$	5,187,665
Less accumulated provision for depreciation		1,407,334		1,276,192

		4,164,158		3,911,473
Construction work-in-progress		576,127		238,518

		4,740,285		4,149,991


Investments and other property, net (Note 4)		19,544		22,176


Current Assets:
Cash and cash equivalents		37,001		36,633
Accounts receivable less allowance for uncollectible accounts:
2007-$30,392, 2006-$32,834		274,242		244,623
Deferred energy costs — electric (Note 1)		75,948		129,304
Materials, supplies and fuel, at average cost		68,671		60,754
Risk management assets (Note 9)		16,078		16,378
Deferred income taxes (Note 10)		2,383		72,294
Deposits and prepayments for energy		280		7,056
Other		28,072		19,901

		502,675		586,943

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		205,030		359,589
Regulatory tax asset (Note 10)		165,257		153,471
Regulatory asset for pension plans (Note 11)		86,909		113,646
Other regulatory assets (Note 1)		524,460		440,369
Risk management assets (Note 9)		9,069		5,379
Risk management regulatory assets — net (Note 9)		17,186		83,886
Unamortized debt issuance costs		36,551		38,856
Other		70,403		33,209

		1,114,865		1,228,405

TOTAL ASSETS	$	6,377,369	$	5,987,515

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	2,376,740	$	2,172,198
Long-term debt		2,528,141		2,380,139

		4,904,881		4,552,337

Current Liabilities:
Current maturities of long-term debt		8,642		5,948
Accounts payable		231,205		148,003
Accounts payable, affiliated companies		32,706		20,656
Accrued interest		41,920		37,010
Dividends declared		10,907		13,472
Accrued salaries and benefits		16,881		14,989
Current income taxes payable (Note 10)		3,544		3,981
Intercompany Income taxes payable		15,403		884
Deferred income taxes (Note 10)		—		—
Risk management liabilities (Note 9)		26,982		84,674
Accrued taxes		4,529		2,671
Deferred energy costs-electric (Note 1)		—		—
Other current liabilities		50,902		48,298

		443,621		380,586

Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes (Note 10)		585,168		599,747
Deferred investment tax credit		11,169		15,213
Regulatory tax liability (Note 10)		10,038		13,451
Customer advances for construction		58,890		60,040
Accrued retirement benefits		25,693		90,474
Risk management liabilities (Note 9)		5,116		7,061
Regulatory liabilities (Note 1)		168,381		171,298
Other		164,412		97,308

		1,028,867		1,054,592


TOTAL CAPITALIZATION AND LIABILITIES	$	6,377,369	$	5,987,515

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

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)


	Year ended December 31,
	2007			2006			2005
OPERATING REVENUES:
Electric	$	2,356,620		$	2,124,081		$	1,883,267

OPERATING EXPENSES:
Operation:
Purchased power		688,606			764,850			963,888
Fuel for power generation		594,382			552,959			277,083
Deferral of energy costs-net		233,166			92,322			(45,668	)
Reinstatement of deferred energy (Note 3)		—			(178,825	)		—
Other		232,610			218,120			211,039
Maintenance		67,482			61,899			52,040
Depreciation and amortization		152,139			141,585			124,098
Taxes:
Income taxes (Note 10)		61,108			91,781			46,425
Other than income		29,823			28,118			25,535

		2,059,316			1,772,809			1,654,440

OPERATING INCOME		297,304			351,272			228,827

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		15,861			11,755			18,683
Interest accrued on deferred energy		14,213			21,902			20,350
Carrying charge for Lenzie (Note 1)		16,080			33,440			—
Reinstated interest on deferred energy (Note 3)		11,076			—			—
Other income		14,423			16,992			25,626
Other expense		(11,352	)		(8,480	)		(8,525	)
Income taxes (Note 10)		(17,244	)		(25,729	)		(17,570	)

		43,057			49,880			38,564

Total Income Before Interest Charges		340,361			401,152			267,391

INTEREST CHARGES:
Long-term debt		164,002			171,188			159,106
Interest for Energy Suppliers (Note 13)		—			—			(14,825	)
Other		23,861			17,038			13,563
Allowance for borrowed funds used during construction		(13,196	)		(11,614	)		(23,187	)

		174,667			176,612			134,657


NET INCOME	$	165,694		$	224,540		$	132,734

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

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year ended December 31,
	2007			2006		2005
NET INCOME	$	165,694		$	224,540	$	132,734

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:

Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $785 in 2005)		—			—		(1,460	)

Minimum pension liability adjustment (net of taxes of ($520) and $740 in 2006 and 2005, respectively)		—			965		(2,769	)
Change in SFAS 158 liability and amortization (net of taxes of $487)		(904	)		—		—


OTHER COMPREHENSIVE INCOME (LOSS)		(904	)		965		(4,229	)

COMPREHENSIVE INCOME	$	164,790		$	225,505	$	128,505

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)


	December 31,
	2007			2006			2005
Common Stock:
Balance at Beginning of Year and End of Year	$	1		$	1		$	1

Other Paid-In Capital:

Balance at Beginning of Year		2,042,369			1,808,848			1,576,794
Revaluation of investment		—			—			119
Transfer of pension assets		—			33,521			—
Capital contribution from parent		65,000			200,000			231,935
Tax Benefit from stock option exercises		213			—			—

Balance at End of Year		2,107,582			2,042,369			1,808,848


Retained Earnings (Deficit):

Balance at Beginning of Year		132,201			(43,422	)		(140,898	)
FIN 48 Adjustment to beginning balance		207			—			—
Income for the year		165,694			224,540			132,734
Common stock dividends declared		(25,667	)		(48,917	)		(35,258	)

Balance at End of Year		272,435			132,201			(43,422	)


Accumulated Other Comprehensive Income (Loss):

Balance at Beginning of Year		(2,373	)		(3,338	)		891
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $785 in 2005)		—			—			(1,460	)
Minimum pension liability adjustment (net of taxes of ($520) and $740 in 2006 and 2005, respectively)		—			965			(2,769	)
Change in SFAS 158 liability and amortization (net of taxes of $487)		(905	)		—			—

Balance at End of Year		(3,278	)		(2,373	)		(3,338	)


Total Common Shareholder’s Equity at End of Year	$	2,376,740		$	2,172,198		$	1,762,089

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

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


	Year Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	165,694		$	224,540		$	132,734
Adjustments to reconcile net income to net cash from or (used by)
operating activities:
Depreciation and amortization		152,139			141,585			124,098
Deferred taxes and deferred investment tax credit		56,868			107,392			86,910
AFUDC		(15,861	)		(11,755	)		(41,870	)
Amortization of deferred energy costs		203,213			120,499			131,471
Deferral of energy costs		15,779			(49,982	)		(186,338	)
Deferral of energy costs — terminated suppliers		—			3,896			155,119
Reinstatement of deferred energy		—			(178,825	)		—
Carrying charge on Lenzie plant		(16,080	)		(33,440	)		—
Reinstated interest on deferred energy		(11,076	)		—			—
Other, net		5,831			3,394			(7,433	)
Changes in certain assets and liabilities:
Accounts receivable		(29,619	)		(35,191	)		(57,746	)
Materials, supplies and fuel		(7,916	)		(13,919	)		(1,977	)
Other current assets		(1,395	)		5,421			14,434
Accounts payable		60,269			(2,431	)		30,855
Payment to terminating supplier		—			(37,410	)		—
Proceeds from claim on terminating supplier		—			26,391			—
Accrued retirement benefits		(46,067	)		(11,853	)		3,589
Other current liabilities		11,267			5,083			(107,575	)
Risk Management assets and liabilities		3,673			(2,219	)		(6,597	)
Other assets		(964	)		(9,902	)		(9,950	)
Other liabilities		18,873			8,907			(35,515	)

Net Cash from Operating Activities		564,628			260,181			224,209


CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(766,136	)		(670,441	)		(546,748	)
AFUDC		15,861			11,755			41,870
Customer advances for construction		(1,150	)		10,417			18,813
Contributions in aid of construction		19,576			21,241			8,544
Investments and other property — net		2,768			7,363			1,875

Net Cash used by Investing Activities		(729,081	)		(619,665	)		(475,646	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		724,391			1,687,726			150,000
Retirement of long-term debt		(596,339	)		(1,554,521	)		(238,486	)
Additional investment by parent company		65,000			200,000			230,541
Dividends paid		(28,231	)		(35,769	)		(35,260	)

Net Cash from Financing Activities		164,821			297,436			106,795


Net Increase (Decrease) in Cash and Cash Equivalents		368			(62,048	)		(144,642	)
Beginning Balance in Cash and Cash Equivalents		36,633			98,681			243,323

Ending Balance in Cash and Cash Equivalents	$	37,001		$	36,633		$	98,681


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	164,704		$	190,023		$	173,775
Income taxes	$	6,760		$	4,714		$	—

The accompanying notes are an integral part of the financial statements

100

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)


	December 31,
	2007			2006
Common Shareholder’s Equity:
Common stock, $1.00 par value, 1,000 shares authorized, issued and Outstanding	$	1		$	1
Other paid-in capital		2,107,582			2,042,369
Retained Earnings		272,435			132,201
Accumulated other comprehensive loss		(3,278	)		(2,373	)

Total Common Shareholder’s Equity		2,376,740			2,172,198


Long-Term Debt:
Secured Debt
Debt Secured by General and Refunding Mortgage Indenture
8.25% Series A due 2011		350,000			350,000
6.50% Series I due 2012		130,000			130,000
9.00% Series G due 2013		17,244			227,500
5.875% Series L due 2015		250,000			250,000
5.95% Series M due 2016		210,000			210,000
6.65% Series N due 2036		370,000			370,000
6.00% Series O due 2018		325,000			325,000
6.75% Series R due 2037		350,000			—

Subtotal		2,002,244			1,862,500

Variable Rate Notes
PCRB Series 2000B due 2009		15,000			15,000
IDRB Series 2000A due 2020		100,000			100,000
PCRB Series 2006 due 2036		39,500			39,500
PCRB Series 2006A due 2032		40,000			40,000
PCRB Series 2006B due 2039		13,000			13,000

Subtotal		207,500			207,500

Unsecured Debt
Revenue Bonds
5.30% Series 1995D due 2011		14,000			14,000
5.45% Series 1995D due 2023		6,300			6,300
5.50% Series 1995C due 2030		44,000			44,000
5.60% Series 1995A due 2030		76,750			76,750
5.90% Series 1995B due 2030		85,000			85,000
5.90% Series 1997A due 2032		52,285			52,285

Subtotal		278,335			278,335

Unamortized bond premium and discount, net		(12,732	)		(12,757	)
Obligations under capital leases		61,424			50,479
Current maturities and sinking fund requirements		(8,642	)		(5,948	)
Other, excluding current portion		12			30

Total Long-Term Debt		2,528,141			2,380,139

TOTAL CAPITALIZATION	$	4,904,881		$	4,552,337

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

101

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


	December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,897,219	$	2,766,672
Less accumulated provision for depreciation		1,119,045		1,057,165

		1,778,174		1,709,507
Construction work-in-progress		492,539		227,500

		2,270,713		1,937,007


Investments and other property, net (Note 4)		570		609


Current Assets:
Cash and cash equivalents		23,807		53,260
Accounts receivable less allowance for uncollectible accounts:
2007 - $5,669; 2006 - $6,732		160,014		170,106
Deferred energy costs — electric (Note 1)		—		38,956
Materials, supplies and fuel, at average cost		48,799		42,990
Risk management assets (Note 9)		6,208		10,927
Deferred income taxes (Note 10)		17,728		—
Deposits and prepayments for energy		862		8,912
Other		16,393		11,184

		273,811		336,335


Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		—		22,697
Regulatory tax asset (Note 10)		102,591		109,699
Regulatory asset for pension plans (Note 11)		43,778		106,666
Other regulatory assets (Note 1)		233,827		228,255
Risk management assets (Note 9)		3,360		2,207
Risk management regulatory assets — net (Note 9)		8,881		39,025
Unamortized debt issuance costs		19,976		17,981
Other		19,017		7,356

		431,430		533,886

TOTAL ASSETS	$	2,976,524	$	2,807,837

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,001,840	$	884,737
Long-term debt		1,084,550		1,070,858

		2,086,390		1,955,595

Current Liabilities:
Current maturities of long-term debt		101,643		2,400
Accounts payable		94,722		89,743
Accounts payable, affiliated companies		19,288		11,769
Accrued interest		15,750		7,200
Dividends declared		5,333		6,736
Accrued salaries and benefits		14,830		15,209
Current income taxes payable (Note 10)		—		—
Intercompany income taxes payable		2,479		9,055
Deferred income taxes (Note 10)		—		8,881
Risk management liabilities (Note 9)		12,527		38,391
Accrued taxes		3,542		3,407
Deferred energy costs-electric (Note 1)		17,573		—
Deferred energy costs — gas (Note 1)		11,369		112
Other current liabilities		15,015		12,013

		314,071		204,916

Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes (Note 10)		267,801		278,515
Deferred investment tax credit		17,726		20,005
Regulatory tax liability (Note 10)		18,407		20,624
Customer advances for construction		41,235		31,855
Accrued retirement benefits		48,025		124,254
Risk management liabilities (Note 9)		2,253		3,685
Regulatory liabilities (Note 1)		135,645		130,605
Other		44,971		37,783

		576,063		647,326

TOTAL CAPITALIZATION AND LIABILITIES	$	2,976,524	$	2,807,837

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

102

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


	Year ended December 31,
	2007			2006			2005
OPERATING REVENUES:
Electric	$	1,038,867		$	1,020,162		$	967,427
Gas		205,430			210,068			178,270

		1,244,297			1,230,230			1,145,697

OPERATING EXPENSES:
Operation:
Purchased power		348,299			344,590			352,098
Fuel for power generation		242,973			247,626			233,653
Gas purchased for resale		150,879			160,739			140,850
Deferred energy costs disallowed (Note 3)		14,171			—			—
Deferral of energy costs — electric — net		63,873			47,043			8,110
Deferral of energy costs — gas — net		10,763			6,947			(749	)
Other		142,348			141,350			131,901
Maintenance		31,553			31,273			26,690
Depreciation and amortization		83,393			87,279			90,569
Taxes:
Income taxes (Note 10)		29,991			23,570			26,038
Other than income		20,097			19,796			20,233

		1,138,340			1,110,213			1,029,393

OPERATING INCOME		105,957			120,017			116,304

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		15,948			6,471			1,639
Interest accrued on deferred energy		865			5,996			7,092
Other income		8,091			9,412			5,940
Other expense		(8,441	)		(8,422	)		(7,493	)
Income taxes (Note 10)		3,982			(4,259	)		(2,341	)

		20,445			9,198			4,837

Total Income Before Interest Charges		126,402			129,215			121,141

INTEREST CHARGES:
Long-term debt		67,502			71,869			69,240
Interest for Energy Suppliers (Note 13)		—			—			(2,396	)
Other		6,004			5,142			3,727
Allowance for borrowed funds used during construction		(12,771	)		(5,505	)		(1,504	)

		60,735			71,506			69,067


NET INCOME		65,667			57,709			52,074

Preferred stock dividend and premium on redemption		—			2,341			3,900

EARNINGS APPLICABLE TO COMMON STOCK	$	65,667		$	55,368		$	48,174

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

103

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year ended December 31,
	2007			2006		2005
NET INCOME	$	65,667		$	57,709	$	52,074

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $370 in 2005)		—			—		(686	)

Minimum pension liability adjustment (net of taxes of ($462) and $632 in 2006 and 2005, respectively)		—			861		(1,173	)
Change in SFAS 158 liability and amortization (net of taxes of $620)		(1,153	)		—		—

OTHER COMPREHENSIVE INCOME (LOSS)		(1,153	)		861		(1,859	)


COMPREHENSIVE INCOME	$	64,514		$	58,570	$	50,215

The accompanying notes are an integral part of the financial statements

104

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)


	December 31,
	2007			2006			2005
Common Stock:
Balance at Beginning of Year and End of Year	$	4		$	4		$	4

Other Paid-In Capital:

Balance at Beginning of Year		935,453			810,103			810,103
Transfer of Goodwill (Note 18)		—			18,888			—
Transfer of pension assets		—			31,462			—
Capital contribution from parent		65,000			75,000			—
Tax Benefit from stock option exercises		142			—			—

Balance at End of Year		1,000,595			935,453			810,103


Retained Earnings (Deficit):

Balance at Beginning of Year		(49,789	)		(80,538	)		(104,779	)
FIN 48 Adjustment to beginning balance		280			—			—
Income before preferred dividends		65,667			57,709			52,074
Preferred stock redemption		—			(1,366	)		—
Preferred stock dividends declared		—			(975	)		(3,900	)
Common stock dividends declared		(12,833	)		(24,619	)		(23,933	)

Balance at End of Year		3,325			(49,789	)		(80,538	)


Accumulated Other Comprehensive Income (Loss):

Balance at Beginning of Year		(931	)		(1,792	)		67
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $370 in 2005)		—			—			(686	)
Minimum pension liability adjustment (net of taxes of ($462) and $632 in 2006 and 2005, respectively)		—			861			(1,173	)
Change in SFAS 158 liability and amortization (net of taxes of $620)		(1,153	)		—			—

Balance at End of Year		(2,084	)		(931	)		(1,792	)


Total Common Shareholder’s Equity at End of Year	$	1,001,840		$	884,737		$	727,777

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

105

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


	Year Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	65,667		$	57,709		$	52,074
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		83,393			87,279			90,569
Deferred taxes and deferred investment tax credit		(36,713	)		(39,361	)		209
AFUDC		(15,948	)		(6,471	)		(3,143	)
Amortization of deferred energy costs — electric		43,694			46,322			56,750
Amortization of deferred energy costs — gas		701			6,234			1,446
Deferral of energy costs — electric		35,532			(4,755	)		(54,765	)
Deferral of energy costs — gas		10,668			436			(2,519	)
Deferral of energy costs — terminated suppliers		—			4,845			62,921
Other, net		14,577			16,935			318
Changes in certain assets and liabilities:
Accounts receivable		10,092			36,171			(11,631	)
Materials, supplies and fuel		(5,809	)		(1,382	)		(10,272	)
Other current assets		2,839			18,204			3,106
Accounts payable		15,010			19,670			11,573
Payment to terminating supplier		—			(27,958	)		—
Proceeds from claim on terminating supplier		—			14,974			—
Accrued retirement benefits		(25,248	)		8,781			(51	)
Other current liabilities		11,196			(925	)		(48,603	)
Risk Management assets and liabilities		6,415			(3,731	)		(88	)
Other assets		3,462			(220	)		—
Other liabilities		(5,349	)		(2,320	)		12,237

Net Cash from by Operating Activities		214,179			230,437			160,131


CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(431,190	)		(315,578	)		(139,646	)
AFUDC		15,948			6,471			3,143
Customer advances for construction		9,380			6,931			8,545
Contributions in aid of construction		12,590			17,551			14,807
Investments and other property — net		39			233			157

Net Cash used by Investing Activities		(393,233	)		(284,392	)		(112,994	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		—			3,612			2,034
Proceeds from issuance of long-term debt		521,992			804,157			—
Retirement of long-term debt		(423,155	)		(742,514	)		(2,504	)
Redemption of preferred stock		—			(51,366	)		—
Investment by parent company		65,000			75,000			—
Dividends paid		(14,236	)		(19,827	)		(27,833	)

Net Cash from Financing Activities		149,601			69,062			(28,303	)


Net Increase (Decrease) in Cash and Cash Equivalents		(29,453	)		15,107			18,834
Beginning Balance in Cash and Cash Equivalents		53,260			38,153			19,319

Ending Balance in Cash and Cash Equivalents	$	23,807		$	53,260		$	38,153


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	59,496		$	83,327		$	71,496
Income taxes	$	64		$	12		$	—

Noncash Activities:
Transfer of Regulatory Asset (Note 3)	$	—		$	18,888		$	—

The accompanying notes are an integral part of the financial statements

106

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)


	December 31,
	2007			2006
Common Shareholder’s Equity:
Common stock, $3.75 par value, 20,000,000 shares authorized, 1,000 shares issued and outstanding	$	4		$	4
Other paid-in capital		1,000,595			935,453
Retained Earnings (Deficit)		3,325			(49,789	)
Accumulated other comprehensive loss		(2,084	)		(931	)

Total Common Shareholder’s Equity		1,001,840			884,737

Long-Term Debt:
Secured Debt
Debt Secured by General and Refunding Mortgage Indenture
8.00% Series A due 2008		99,243			320,000
6.25% Series H due 2012		100,000			100,000
6.00% Series M due 2016		300,000			300,000
5.00% Series 2001 due 2036		—			80,000
6.75% Series P due 2037		325,000			—

Subtotal		824,243			800,000

Variable Rate Notes
PCRB Series 2006 due 2029		49,750			49,750
PCRB Series 2006A due 2031		58,700			58,700
PCRB Series 2006B due 2036		75,000			75,000
PCRB Series 2006C due 2036		84,800			84,800
WFRB Series 2007A due 2036		40,000			—
WFRB Series 2007B due 2036		40,000			—

Subtotal		348,250			268,250


Unsecured Debt
Unamortized bond premium and discount, net		10,700			(392	)
Current maturities and sinking fund requirements		(101,643	)		(2,400	)
Other, excluding current portion		3,000			5,400

Total Long-Term Debt		1,084,550			1,070,858

TOTAL CAPITALIZATION	$	2,086,390		$	1,955,595

The accompanying notes are an integral part of the financial statements

107

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 Sierra Pacific Resources (SPR) and its wholly-owned subsidiaries, Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Lands of Sierra, Inc. (LOS), Sierra Energy Company dba e ·three (e ·three), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and Sierra Gas Holding Company (SGHC). All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 67% of the consolidated assets of SPR at December 31, 2007. NPC provides electricity to approximately 826,000 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 SPR include NPC’s wholly-owned subsidiary, Nevada Electric Investment Company (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 31% of the consolidated assets of SPR at December 31, 2007. SPPC provides electricity to approximately 366,000 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 149,000 customers in an area of about 600 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC include the accounts of SPPC’s wholly-owned subsidiaries, Piñon Pine Corporation, Piñon Pine Investment Company, 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 Federal Energy Regulatory Commission (FERC).

TGPC was a partner in a joint venture that developed, constructed and operates a natural gas pipeline serving the expanding gas market in the Reno area and certain northeastern California markets. TGPC accounted for its joint venture interest under the equity method. In December 2006, TGPC substantially sold its partnership interest in the joint venture. The remaining partnership interest was sold in 2007. See Note 4, Investment in Subsidiaries and Other Property.

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are currently subject to the approval of the Public Utilities Commission of Nevada (PUCN) and, in the case of SPPC, rates are also subject to the approval of the California Public Utility Commission (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 Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” issued by the Financial Accounting Standards Board (FASB). 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. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 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 SFAS No. 71 are satisfied.

In addition to the deferral of energy costs discussed below, items to which SPR and the Utilities apply regulatory accounting are included in the tables below.

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 and pending or potential deregulation legislation.

108

Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and the Utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation could also require affected utilities to write off their associated regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Utilities’ future financial position and results of operations.

SIERRA PACIFIC RESOURCES
OTHER REGULATORY ASSETS AND LIABILITIES
(Dollars in Thousands)


	As of December 31, 2007
		Receiving
		Regulatory
		Treatment										As of
	Remaining			Not			Pending					December
	Amortization	Earning a		Earning			Regulatory			2007		31, 2006
DESCRIPTION	Period	Return(1)		a Return			Treatment			Total		Total
Regulatory Assets
Lost on reacquired debt	Term of related debt	$	100,271	$	—		$	—		$	100,271	$	87,154
Lenzie	2042		—		38,619			41,665			80,284		52,456
Mohave Plant and deferred costs	2015		25,440		(3,287	)		(3,929	)		18,224		17,835
Clark units 1-3	Various thru 2011		9,095		—			7,050			16,145		16,735
Piñon Pine	Various thru 2029		33,665		5,556			1,408			40,629		42,001
Plant assets	Various thru 2031		2,694		—			320			3,014		2,876
Asset retirement obligations			—		—			36,498			36,498		16,112
Nevada divestiture costs	2012		19,469		—			—			19,469		23,983
Merger transition/transaction costs	2016		—		25,006			—			25,006		28,916
Merger severance/relocation	2016		—		13,761			—			13,762		15,884
Merger goodwill	2046		—		285,365			—			285,365		293,199
California restructure costs	Thru 2009		490		550			—			1,040		1,859
Conservation programs	Thru 2012		36,694		—			42,349			79,043		53,275
Legal costs			—		—			7,138			7,138		8,376
Peabody coal costs			—		—			17,406			17,406		—
Legal fees — Western Energy Crisis	2010		5,259		—			—			5,259		—
Other costs	Thru 2017		1,068		4,719			3,948			9,735		7,963

Subtotal		$	234,145	$	370,289		$	153,853		$	758,287	$	668,624

Regulatory asset for pension plan			—		133,984			—			133,984		223,218

Total regulatory assets		$	234,145	$	504,273		$	153,853		$	892,271	$	891,842


Regulatory Liabilities
Cost of removal	Various	$	291,274	$	—		$	—		$	291,274	$	283,641
Gain on property sales	Various thru 2008		1,829		—			—			1,829		4,531
SO2 allowances	Various thru 2013		746		—			—			746		745
Plant liability	2008		259		—			—			259		1,038
Impact charge	2008		711		—			—			711		2,722
Depreciation customer advances			—		—			8,745			8,745		8,775
Domestic production tax deduction			—		—			380			380		—
Other	2008		—		82			—			82		451

Total regulatory liabilities		$	294,819	$	82		$	9,125		$	304,026	$	301,903

109

NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES
(Dollars in Thousands)


	As of December 31, 2007
		Receiving
		Regulatory
		Treatment										As of
	Remaining			Not			Pending					December
	Amortization	Earning a		Earning			Regulatory			2007		31, 2006
DESCRIPTION	Period	Return(1)		a Return			Treatment			Total		Total
Regulatory Assets
Lost on reacquired debt	Term of related debt	$	67,414	$	—		$	—		$	67,414	$	60,026
Lenzie	2042		—		38,619			41,665			80,284		52,456
Mohave	2015		25,440		(3,287	)		(3,929	)		18,224		17,835
Clark units 1-3	2011		9,095		—			7,050			16,145		16,735
Asset retirement obligations			—		—			32,059			32,059		11,081
Nevada divestiture costs	2012		11,872		—			—			11,872		14,665
Merger transition/transaction costs	2014		—		17,446			—			17,446		20,237
Merger severance/relocation	2014		—		6,376			—			6,376		7,397
Merger goodwill	2044		—		179,436			—			179,436		184,386
Conservation programs	2013		33,367		—			29,813			63,180		42,636
Legal costs			—		—			7,138			7,138		8,376
Peabody coal costs			—		—			17,406			17,406		—
Legal fees — Western Energy Crisis	2010		2,801		—			—			2,801		—
Other costs	2009		551		4,128			—			4,679		4,539

Subtotal		$	150,540	$	242,718		$	131,202		$	524,460	$	440,369

Regulatory asset for pension plan			—		86,909			—			86,909		113,646

Total regulatory assets		$	150,540	$	329,627		$	131,202		$	611,369	$	554,015


Regulatory Liabilities
Cost of removal	Various	$	161,690	$	—		$	—		$	161,690	$	162,196
Gain on property sales	2008		1,829		—			—			1,829		4,531
SO2 allowances	Various thru 2013		746		—			—			746		745
Depreciation customer advances			—		—			3,736			3,736		3,701
Domestic production tax deduction			—		—			380			380		—
Other			—		—			—			—		125

Total regulatory liabilities		$	164,265	$	—		$	4,116		$	168,381	$	171,298

SIERRA PACIFIC POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES
(Dollars in Thousands)


	As of December 31, 2007
		Receiving
		Regulatory
		Treatment								As of
	Remaining			Not		Pending				December
	Amortization	Earning a		Earning		Regulatory		2007		31, 2006
DESCRIPTION	Period	Return(1)		a Return		Treatment		Total		Total
Regulatory Assets
Loss on reacquired debt	Term of related debt	$	32,857	$	—	$	—	$	32,857	$	27,128
Piñon Pine	Various thru 2029		33,665		5,556		1,408		40,629		42,001
Plant assets	Various thru 2031		2,694		—		320		3,014		2,876
Asset retirement obligations			—		—		4,439		4,439		5,031
Nevada divestiture costs	2012		7,957		—		—		7,597		9,318
Merger transition/transaction costs	2016		—		7,560		—		7,560		8,679
Merger severance/relocation	2016		—		7,385		—		7,385		8,487
Merger goodwill	2046		—		105,929		—		105,929		108,813
California restructure costs	Thru 2009		490		550		—		1,040		1,859
Conservation programs	Thru 2012		3,327		—		12,536		15,863		10,639
Legal fees — Western Energy Crisis			2,458		—		—		2,458		—
Other costs	Various thru 2017		517		591		3,948		5,056		3,424

Subtotal		$	83,605	$	127,571	$	22,651	$	233,827	$	228,255

Regulatory asset for pension plan			—		43,778		—		43,778		106,666

Total regulatory assets		$	83,605	$	171,349	$	22,651	$	277,605	$	334,921


Regulatory Liabilities
Cost of removal	Various	$	129,584	$	—	$	—	$	129,584	$	121,445
Plant liability	2008		259		—		—		259		1,038
Impact charge	2008		711		—		—		711		2,722
Depreciation customer advances			—		—		5,009		5,009		5,074
Other	2008		—		82		—		82		326

Total regulatory liabilities		$	130,554	$	82	$	5,009	$	135,645	$	130,605


⁽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.

110

Deferral of Energy Costs

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 SFAS No. 71. 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 deferred energy accounting adjustment 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.

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


		December 31, 2007
		NPC			SPPC			SPPC			SPR
Description		Electric			Electric			Gas			Total
Unamortized balances approved for collection in current rates
Reinstatement of Deferred Energy	(effective 6/07, 10 years)⁽¹⁾	$	179,409		$	—		$	—		$	179,409
Electric — NPC Period 5	(effective 8/06, 2 years)		53,876			—			—			53,876
Electric — SPPC Period 5	(effective 7/06, 2 years)		—			5,733			—			5,733
Electric — NPC Period 6	(effective 6/07, 14 months)		26,048			—			—			26,048
Electric — SPPC Period 6	(effective 7/07, 1 year)		—			7,524			—			7,524
Natural Gas — Period 6	(effective 12/06, 1 year)		—			—			161			161
Natural Gas — Period 7	(effective 12/07, 1 year)		—			—			(1,369	)		(1,369	)
Western Energy Crisis Rate Case-NPC⁽²⁾	(effective 6/07, 3 years)		65,344			—			—			65,344
Balances pending PUCN approval⁽³⁾			(43,699	)		(34,198	)		(10,161	)		(88,058	)
Cumulative CPUC Balance			—			3,368			—			3,368

Total		$	280,978		$	(17,573	)	$	(11,369	)	$	252,036


Current Assets
Deferred energy costs — electric		$	75,948		$	—		$	—		$	75,948
Deferred Assets
Deferred energy costs — electric			205,030			—			—			205,030
Current Liabilities
Deferred energy costs — electric			—			(17,573	)		—			(17,573	)
Deferred energy costs — gas			—			—			(11,369	)		(11,369	)

Total		$	280,978		$	(17,573	)	$	(11,369	)	$	252,036


		December 31, 2006
		NPC			SPPC			SPPC			SPR
		Electric			Electric			Gas			Total
Unamortized balances approved for collection in current rate
Electric — NPC Period 1	(Reinstatement of deferred energy)(1)	$	178,825		$	—		$	—		$	178,825
Electric — NPC Period 3	(effective 4/05, 2 years)		(4,067	)		—			—			(4,067	)
Electric — SPPC Period 3	(effective 6/05, 27 month)		—			6,034			—			6,034
Electric — NPC Period 4	(effective 4/05, 2 years)		6,347			—			—			6,347
Electric — NPC Period 5	(effective 8/06, 2 years)		153,720			—			—			153,720
Electric — SPPC Period 5	(effective 7/06, 2 years)		—			27,657			—			27,657
Nat. Gas — Per 6, LPG — Per 5	(effective 12/06, 1 year)		—			—			902			902
Balances pending PUCN approval			72,280			16,220			—			88,500
Cumulative CPUC Balance			—			9,956			—			9,956
Balances accrued since end of periods submitted for PUCN approval			1,693			(14,479	)		(1,014	)		(13,800	)
Claims for terminated supply contracts⁽²⁾			80,095			16,265			—			96,360

Total		$	488,893		$	61,653		$	(112	)⁽³⁾	$	550,434


Current Assets
Deferred energy costs — electric		$	129,304		$	38,956		$	—		$	168,260
Deferred Assets
Deferred energy costs — electric			359,589			22,697			—			382,286
Current Liabilities
Deferred energy costs — gas			—			—			(112	)		(112	)

Total		$	488,893		$	61,653			(112	)	$	550,434


(1)		Reinstatement of Deferred Energy is discussed in Note 3, Regulatory Actions.

(2)		NPC’s Western Energy Crisis Rate Case is discussed in Note 3, Regulatory Actions

(3)		Credit balances represent potential refunds to the Utilities’ customers.

Carrying Charge on the Lenzie Generating Station

In 2004, the Public Utilities Commission of Nevada (PUCN) granted NPC’s request to designate the Chuck Lenzie Generating Station (Lenzie) as a critical facility and allowed a 2% enhanced Return on Equity (ROE) to be applied to the Lenzie construction costs expended after acquisition. The order allowed for an additional 1% enhanced ROE if the two Lenzie generating 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, $8.1 million ($8.0 million as of December 31, 2007) of this amount was not recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through rates. For the year ended December 31, 2007, NPC recognized $16.1 million in income. NPC no longer records a separate carrying charge component related to Lenzie as the carrying charge is in current rates effective June 1, as discussed below.

In May 2007, the PUCN issued its order on NPC’s 2006 General Rate Case (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 Lenzie through rates rather than as a separate carrying charge component. NPC will seek recovery of the remaining $27.3 million of carrying charges calculated subsequent to the certification period in its next GRC.

Mohave Generation Station (Mohave)

NPC owns approximately 14% of the Mohave facility. Southern California Edison (SCE) is the operating partner of Mohave.

When operating, Mohave 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 Mohave 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 Mohave, 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, Mohave 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.

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In December 2005, the Owners of the Mohave plant suspended operation, pending resolution of these issues. However, in June 2006, majority stake holder SCE 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 Mohave.

In NPC’s 2006 GRC, the PUCN approved the recovery of the net book value of the plant and costs and savings related to the plant through the certification period of October 31, 2006. The balance to be recovered, over an eight year period, is approximately $22.2 million as of December 31, 2007 and is recorded in Other Regulatory Assets. All costs incurred subsequent to the certification period will continue to be accumulated in Other Regulatory Assets and NPC will seek recovery in its next GRC for those costs. The accumulated credit balance subsequent to the certification period is approximately $3.9 million as of December 31, 2007.

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 allowance for funds used during construction (AFUDC) which includes the cost of debt and equity capital associated with construction activity.

Allowance for Funds Used During Construction

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 2007 was 9.06% and 9.03% during 2006 and 2005. SPPC’s AFUDC rates used during 2007, 2006 and 2005 were 8.60%, 8.97% and 8.96%, 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 for 2007 approximately 2.66% , and 3.15% during 2006 and 2005. SPPC’s depreciation provision for 2007, 2006 and 2005, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 3.01%, 3.08% and 3.3%, respectively.

Impairment of Long-Lived Assets

SPR, 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 SFAS No. 144, “Accounting for the Disposal or Impairment of Long-Lived Assets” (SFAS 144).

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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.

Federal Income Taxes

SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiary’s respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, 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.

For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the difference between straight-line and accelerated tax depreciation on post-1969 utility plant expansion property, deferred energy, and certain other differences between financial reporting and taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred taxes on the benefits derived from using the Modified Accelerated Cost Recovery System.

Deferred investment tax credits are being amortized over the estimated service lives of the related properties. Investment tax credits are no longer available to the Utilities.

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.

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 and the Utilities’ current tariffs. Accounts receivable as of December 31, 2007, include unbilled receivables of $106 million and $79 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2006, include unbilled receivables of $92 million and $83 million for NPC and SPPC, respectively.

Asset Retirement Obligations

SFAS No. 143 “Accounting for Asset Retirement Obligations” provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, 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 SFAS No. 143 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. SPR, NPC and SPPC adopted SFAS No. 143 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. The land on which the Navajo generating station resides is leased from the Navajo Nation. Provisions of the lease require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases.

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In March, 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 as clarification to SFAS No. 143. This Interpretation was effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year enterprises). The Interpretation clarified the term conditional retirement obligation as used in SFAS No. 143 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 under SFAS 143, 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 of FIN 47.

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):


	SPR				NPC					SPPC
	2007		2006		2007			2006		2007		2006
Balance at January 1	$	18,194	$	17,082	$	12,895		$	12,097	$	5,299	$	4,985
Liabilities incurred in current period		32,867		—		32,867			—		—		—
Liabilities settled in current period		—		—		—			—		—		—
Accretion expense		1,879		1,112		1,488			798		391		314
Revision in estimated cash flows		522		—		(980	)		—		1,502		—

Balance at December 31	$	53,462	$	18,194	$	46,270		$	12,895	$	7,192	$	5,299

The significant increase to NPC’s ARO balance is primarily related to the Reid Gardner Generating Station. An adjustment of approximately $12 million was made to the original ARO costs due to revised estimates for the evaporative ponds. In addition, approximately $20 million was added to the ARO balance as a result of the Administrative Order on Consent between Nevada Division of Environmental Protection and NPC as discussed further in Note 13. Commitments and Contingencies.

Cost of Removal

In addition to the legal asset retirement obligations booked under SFAS 143 and FIN 47, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets, in accordance with accepted accounting practices. The amounts of such accruals included in regulatory liabilities in 2007 are approximately $161.7 million and $129.6 million for NPC and SPPC, respectively. In 2006, the amounts were approximately $162.2 million and $121.3 million.

Variable Interest Entities

In December 2003, the FASB issued a revised Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46 (R)), which elaborates on Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” Among other requirements, FIN 46 (R) provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. As of December 2003, SPR, NPC and SPPC adopted FIN 46 (R) for special purpose entities. In 2004, SPR, NPC and SPPC adopted FIN 46 (R) for all variable interest entities. To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with qualifying facilities (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 FIN 46 (R) 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, 2007.

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Recent Pronouncements

SFAS 157

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurement” (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. The provisions of SFAS 157 are effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. SFAS 157 was effective for SPR and the Utilities beginning January 1, 2008. SPR and the Utilities do not expect the adoption of SFAS 157 to have a material impact on the consolidated financial statements.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. The objective of the statement is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of SFAS 159 are effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. SFAS 159 was effective for SPR and the Utilities beginning January 1, 2008. SPR and the Utilities do not expect the adoption of SFAS 159 to have a material impact on the consolidated financial statements.

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NOTE 2. SEGMENT INFORMATION

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

Operational information of the different business segments is set forth below based on the nature of products and services offered. SPR 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. NPC’s operating income for the year ended December 31, 2006 includes the reinstatement of deferred energy costs of $178.8 and SPPC’s operating income for the year ended December 31, 2007 includes deferred energy costs disallowed of $14.2 million, which are not reflected in their respective gross margin (dollars in thousands).


							SPPC
	NPC		SPPC		SPPC		Reconciling		SPPC		SPR			SPR
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:
Purchase Power	$	688,606	$	348,299	$	—			$	348,299				$	1,036,905
Fuel for power generation	$	594,382	$	242,973	$	—			$	242,973				$	837,355
Gas purchased for resale	$	—	$	—	$	150,879			$	150,879				$	150,879
Deferred energy costs — net	$	233,166	$	63,873	$	10,763			$	74,636				$	307,802

	$	1,516,154	$	655,145	$	161,642			$	816,787	$	—		$	2,332,941


Gross Margin	$	840,466	$	383,722	$	43,788			$	427,510	$	43		$	1,268,019


Deferred energy costs disallowed	$	—							$	14,171	$	—		$	14,171
Other	$	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:
Income taxes	$	61,108							$	29,991	$	(15,944	)	$	75,155
Other than income	$	29,823							$	20,097	$	193		$	50,113


Operating Income	$	297,304							$	105,957	$	11,306		$	414,567


Assets	$	6,377,369	$	2,665,943	$	273,220	$	37,361	$	2,976,524	$	110,857		$	9,464,750


Capital expenditures	$	766,136	$	389,427	$	41,763			$	431,190				$	1,197,326

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								SPPC
	NPC			SPPC		SPPC		Reconciling		SPPC		SPR			SPR
December 31, 2006	Electric			Electric		Gas		Eliminations⁽¹⁾		Total		Other			Consolidated
Operating Revenues	$	2,124,081		$	1,020,162	$	210,068			$	1,230,230	$	1,639		$	3,355,950
Energy Costs:
Purchase Power	$	764,850		$	344,590					$	344,590				$	1,109,440
Fuel for power generation	$	552,959		$	247,626					$	247,626				$	800,585
Gas purchased for resale	$	—		$	—	$	160,739			$	160,739				$	160,739
Deferred energy costs — net	$	92,322		$	47,043	$	6,947			$	53,990				$	146,312

	$	1,410,131		$	639,259	$	167,686			$	806,945	$	—		$	2,217,076


Gross Margin	$	713,950		$	380,903	$	42,382			$	423,285	$	1,639		$	1,138,874


Reinstatement of deferred energy costs	$	(178,825	)							$	—	$	—		$	(178,825	)
Other	$	218,120								$	141,350	$	7,728		$	367,198
Maintenance	$	61,899								$	31,273	$	—		$	93,172
Depreciation and amortization	$	141,585								$	87,279	$	11		$	228,875
Taxes:
Income taxes	$	91,781								$	23,570	$	(23,780	)	$	91,571
Other than income	$	28,118								$	19,796	$	172		$	48,086


Operating Income	$	351,272								$	120,017	$	17,508		$	488,797


Assets	$	5,987,515		$	2,476,483	$	275,294	$	56,060	$	2,807,837	$	36,724		$	8,832,076


Capital expenditures	$	670,441		$	282,641	$	32,937			$	315,578				$	986,019


									SPPC
	NPC			SPPC		SPPC			Reconciling		SPPC		SPR			SPR
December 31, 2005	Electric			Electric		Gas			Eliminations⁽¹⁾		Total		Other			Consolidated
Operating Revenues	$	1,883,267		$	967,427	$	178,270				$	1,145,697	$	1,278		$	3,030,242
Energy Costs:
Purchase Power	$	963,888		$	352,098						$	352,098				$	1,315,986
Fuel for power generation	$	277,083		$	233,653						$	233,653				$	510,736
Gas purchased for resale	$	—		$	—	$	140,850				$	140,850				$	140,850
Deferred energy costs — net	$	(45,668	)	$	8,110	$	(749	)			$	7,361				$	(38,307	)

	$	1,195,303		$	593,861	$	140,101				$	733,962	$	—		$	1,929,265


Gross Margin	$	687,964		$	373,566	$	38,169				$	411,735	$	1,278		$	1,100,977


Other	$	211,039									$	131,901	$	20,862		$	363,802
Maintenance	$	52,040									$	26,690	$	—		$	78,730
Depreciation and amortization	$	124,098									$	90,569	$	(5	)	$	214,662
Taxes:
Income taxes	$	46,425									$	26,038	$	(33,278	)	$	39,185
Other than income	$	25,535									$	20,233	$	152		$	45,920


Operating Income	$	228,827									$	116,304	$	13,547		$	358,678


Assets	$	5,173,921		$	2,218,938	$	—		$	81,656	$	2,546,301	$	150,324		$	7,870,546


Capital expenditures	$	546,748		$	121,767	$	—				$	139,646				$	686,394
																			~ ~~~~~~~~~


(1)		The reconciliation of segment assets at December 31, 2007, 2006, and 2005 to the consolidated total includes the following unallocated amounts:


	2007		2006		2005
Cash	$	23,807	$	53,260	$	53,024
Other regulatory assets		—		—		19,265
Deferred charges-other		13,554		2,800		9,367

	$	37,361	$	56,060	$	81,656

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NOTE 3. REGULATORY ACTIONS

Pending Rate Cases

Nevada Power Company

NPC Fifth Amendment to 2006 Integrated Resource Plan (IRP)

In December 2007, NPC filed its fifth amendment to its 2006 IRP requesting approval of three items: 1) a revised Demand Side Management plan; 2) a settlement agreement and new long-term power purchase agreement for approximately 50 MW of summer season capacity; and 3) a new long-term tolling agreement that will provide 570 MW of unit contingent summer season capacity.

Sierra Pacific Power Company

SPPC Nevada Gas BTER Filing

In December 2007, SPPC filed an application for the authority to implement quarterly BTER adjustments for its natural gas and liquefied propane gas services. Approval of this application will not affect SPPC customers until the first notice of quarterly adjustment to the BTER is filed and implemented.

SPPC Nevada 2007 General Rate Case

In December 2007, SPPC filed its statutorily required electric GRC utilizing the hybrid methodology that was ratified by the 2007 Nevada Legislature. The hybrid methodology incorporates historical costs and certain projected costs. Under this new methodology, the projected costs must be known and measurable and must begin prior to the rate effective date.

In its GRC, SPPC is requesting the following:

	•		Increase in general rates by $110.8 million, approximately a 12.5% increase;

	•		Return on equity (ROE) and rate of return (ROR) of 11.5% and 8.73%, respectively;

	•		Authorization to recover the costs of major plant additions including a new 541 MW combined cycle generating plant and new transmission / distribution facilities; and

	•		Authorization to recover the projected operating and maintenance costs associated with the new combined cycle generating plant.

SPPC expects the new rates to be in effect on July 1, 2008.

Other Pending Matters

SPPC Nevada 2003 General Rate Case

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 Department of Energy (DOE) Clean Coal 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 integrated electric resource plan. 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. 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 (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 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 its January 25, 2006 order, remanded the matter back to the PUCN for further review.

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A pre-hearing conference on this matter was held in June 2007, during which the parties were directed to file briefs on the scope of the issues they believe are before the PUCN. A second pre-hearing conference was held in August 2007 in which the PUCN determined the scope of the proceedings and set a procedural schedule. Hearings were held in early January 2008.

Approved Rate Cases

Nevada Power Company

NPC 2007 Quarterly BTER Filings

November

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.

August

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 Fourth Amendment to 2006 Integrated Resource Plan (IRP)

In July 2007, NPC filed its fourth amendment to its 2006 IRP requesting to expend $13.2 million on various transmission projects. In addition, NPC requested approval of various renewable energy purchase power agreements, totaling 139.5 megawatts (MWs), to be built over the next two to four years.

In November 2007, the PUCN approved the amendment to the IRP with the exception of the amounts to be spent on transmission projects. The PUCN requested that NPC further evaluate the total projected costs of the transmission project and re-submit the request.

NPC 2007 Deferred Energy Rate Case 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.

Material Amendments to NPC’s 2006 Integrated Resource Plan

In January 2007, NPC filed an amendment to its 2006 IRP requesting approval to expend $60 million to install new ultra-low emission burners on the four combustion turbines serving the combined cycle units at the Clark Generating Station.

In May 2007, the PUCN approved a stipulation pursuant to which NPC was authorized to expend $60 million to install the new ultra-low emission burners.

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.

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NPC 2001 Deferred Energy Case

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 Bureau of Consumer Protection (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 $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 General Rate Case

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 Lenzie;

	•		authorized recovery of accumulated cost and savings, including the net book value of Mohave over an eight year period, see Note 1, Significant Accounting Policies for further discussion of Mohave.

Sierra Pacific Power Company

SPPC 2007 Quarterly Electric BTER Filings

November

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.

August

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 Integrated Resource Plan

In June 2007, SPPC filed its 2007 triennial IRP with the PUCN. The following are the key elements of the filing:

•		requested approval for approximately $176 million in transmission projects;

•		requested approval of four new demand side programs and to increase spending on seven existing demand side programs (total expenditures of $28.4 million). The demand side programs are intended to help customers use electricity more efficiently and also contribute to SPPC’s Renewable Portfolio requirements; and

•		requested approval to expend $16.5 million, an increase of $8.2 million, on the replacement of the diesel units in Kings Beach, California. The increase in costs is the result of higher material costs and the costs to meet the environmental requirements of the Tahoe Regional Planning Administration.

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In December 2007, the PUCN approved the IRP with the exception of a transmission project estimated at $91 million. In connection with that transmission project, SPPC was ordered to investigate only the feasibility of permitting the project.

SPPC 2007 Nevada Natural Gas and Propane Deferred Energy Rate Case 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.

SPPC 2006 Nevada Electric Deferred Energy Rate Case 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

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’s developed and filed a cost based filing, which justified a $6 million reduction to the estimated refunds resulting in a $13 million refund.

The CAISO and CALPX currently owe NPC approximately $19 million for power delivered during the same timeframe and a $13 million refund would reduce the amount owed to Nevada Power to $6 million. NPC previously recorded a reserve against the $19 million receivable in 2001.

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.

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The 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):

Sierra Pacific Resources


	December 31,
	2007		2006
Investment in Tuscarora Gas
Transmission Company⁽¹⁾	$	—	$	590
Cash Value-Life Insurance		2,401		12,891
Non-utility property of NEICO		5,136		5,101
Non-utility property of SPCOM		10,000		10,000
Property not designated for Utility use		12,577		4,793
Other non-utility Property		947		950

	$	31,061	$	34,325


(1)		Tuscarora Gas Pipeline Company (TGPC), which is wholly owned by SPR, sold its interest in Tuscarora Gas Transmission Company during December 2006 for approximately $100 million. The gain on the sale of the investment was approximately $40.9 million after taxes. The remaining 1% interest in Tuscarora Gas Transmission Company was sold during December 2007 for approximately $1.9 million. The gain on the sale of the remaining investment was approximately $890 thousand after taxes.

Nevada Power


	December 31,
	2007		2006
Cash Value-Life Insurance	$	2,401	$	12,891
Non-utility property of NEICO		5,136		5,101
Property not designated for Utility use		12,007		4,184

	$	19,544	$	22,176

Sierra Pacific Power


	December 31,
	2007		2006
Property not designated for Utility use	$	570	$	609

NOTE 5. JOINTLY OWNED FACILITIES

At December 31, 2007, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities:


									Construction
	%		Plant		Accumulated		Net Plant		Work in
	Owned		in Service		Depreciation		in Service		Progress
NPC
Navajo Facility		11.3	$	245,437	$	134,731	$	110,706	$	953
Reid Gardner No. 4		32.2		130,653		98,371		32,282		27,496
Silverhawk		75.0		235,716		38,372		197,344		23

			$	611,806	$	271,474	$	340,332	$	28,472


SPPC
Valmy Facility		50.0	$	306,540	$	184,491	$	122,049	$	8,210

The amounts for Navajo include NPC’s share of transmission systems, general plant equipment and NPC’s share of the jointly owned 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 Operations.

Reid Gardner Unit No. 4 is owned by the California Department of Water Resources (67.8%) and NPC (32.2%). NPC is the operating agent. Contractually, NPC is entitled to receive 25 MW of base load capacity and 227 MW of peaking capacity. Operationally, Unit No. 4 subject to heat input limitations is rated at 252 MW, NPC is entitled to use 100% of the unit’s peaking capacity for 1,500 hours each year and is entitled to 9.6% of the first 250 MW of capacity and associated energy. NPC’s share of the operating expenses for this facility is included in the corresponding operating expenses in its Consolidated Statement of Operations.

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NPC is the operator of the Silverhawk generating station, which is jointly owned with Southern Nevada Water Authority. NPC owns 75% and its share of direct operation and maintenance expense is included in its accompanying Consolidated Statement of Operations.

SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operator of the plant for both parties. SPPC’s share of direct operation and maintenance expenses for Valmy is included in its accompanying Consolidated Statement of Operations.

NOTE 6. LONG-TERM DEBT

As of December 31, 2007, NPC’s, SPPC’s and SPR’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):


						SPR
						Holding
						Co. and
						Other		SPR
	NPC			SPPC		Subs.		Consolidated
2008	$	7,170		$	101,643	$	—	$	108,813
2009		22,218			600		—		22,818
2010		8,004			—		—		8,004
2011		369,924			—		—		369,924
2012		136,449			100,000		63,670		300,119

		543,765			202,243		63,670		809,678
Thereafter		2,005,750			973,250		460,539		3,439,539

		2,549,515			1,175,493		524,209		4,249,217
Unamortized Premium (Discount) Amount		(12,732	)		10,700		964		(1,068	)

Total	$	2,536,783		$	1,186,193	$	525,173	$	4,248,149

The preceding table includes obligations related to capital lease obligations discussed under lease commitments within this note.

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.

Nevada Power Company

6.75% General and Refunding Mortgage Notes, Series R

On June 28, 2007, NPC issued and sold $350 million of its 6.750% General and Refunding Mortgage Notes, Series R, due July 1, 2037. The Series R Notes were issued pursuant to a registration statement previously filed with the Securities and Exchange Commission. The net proceeds from the issuance were used to fund the purchase of the tendered Series G Notes (discussed below), repay amounts outstanding under NPC’s revolving credit facility, and for general corporate purposes.

Pollution Control Refunding Revenue Bonds, Series 2006, 2006A and 2006B

In August 2006, on behalf of NPC, Clark County, Nevada (Clark County) issued $39.5 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due January 2036. On the same date, on behalf of NPC, Coconino County, Arizona Pollution Control Corporation (Coconino County) issued $40 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006A, due September 2032, and $13 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006B, due March 2039.

In connection with the issuance of these Bonds, NPC entered into financing agreements with Clark County and Coconino County, pursuant to which Clark County and Coconino County loaned the proceeds from the sales of the bonds to NPC. NPC’s payment obligations under the financing agreements are secured by NPC’s General and Refunding Mortgage Notes, Series P.

The interest rates of the Bonds were initially determined by an auction. The method of determining the interest rate on the Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.

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The proceeds of the offering were used to refund the following, all of which were previously issued for the benefit of NPC:

	•		$39.5 million principal amount of Clark County’s Pollution Control Refunding Revenue Bonds, Series 1992B,

	•		$20 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1996,

	•		$20 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1997B, and

	•		$13 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1995E.

General and Refunding Mortgage Notes, Series O

In May 2006, NPC issued and sold $250 million in aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018. The Series O Notes were issued with registration rights. Proceeds of the offering, together with available cash, were utilized to:

	•		fund the early redemption of $78 million aggregate principal amounts of NPC’s 7.2% Industrial Development Revenue Bonds, Series 1992 C, due 2022,

	•		fund the early redemption, in June 2006, of approximately $72.2 million aggregate principal amount of NPC’s 7.75% Junior Subordinated Debentures due 2038 (when the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 7.75% Cumulative Quarterly Preferred Securities of NVP Capital III, a wholly-owned subsidiary of NPC),

	•		repay amounts outstanding under NPC’s revolving credit facility.

In June 2006, NPC issued an additional $75 million in aggregate principal amount of its 6.5% General and Refunding Mortgage Notes, Series O, as part of the same series as the original Series O Notes. The aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018, outstanding is $325 million as of December 31, 2006. The proceeds from the second issuance, along with the proceeds from an offering of $120 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036 (described below) were used to pay the total consideration for the tender offer for the 10.875% General and Refunding Mortgage Notes, Series E, described below.

General and Refunding Mortgage Notes, Series N

In April 2006, NPC issued and sold $250 million of its 6.65% General and Refunding Mortgage Notes, Series N, due April 2036. The Series N Notes were issued with registration rights. Proceeds of the offering, together with available cash, were utilized to:

	•		fund the early redemption of $35 million aggregate principal amount of NPC’s 8.50% Series Z First Mortgage Bonds due 2023 plus approximately $1 million of associated redemption premiums,

	•		fund the early redemption of $105 million aggregate principal amount of 6.70% Industrial Development Revenue Bonds, due 2022, and

	•		fund the early redemption of approximately $122.5 million aggregate principal amount of NPC’s 8.20% Junior Subordinated Debentures due 2037 (when the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 8.20% Cumulative Quarterly Preferred Securities of NVP Capital I, a wholly-owned subsidiary of NPC).

In June 2006, NPC issued an additional $120 million in aggregate principal amount of its 6.65% General and Refunding Mortgage Notes, Series N, as part of the same series as the original Series N Notes. The aggregate principal amount of 6.65% General and Refunding Mortgage Notes, Series N, due 2036, outstanding is $370 million as of December 31, 2006. The proceeds from the second issuance, along with the proceeds from an offering of $75 million of NPC’s 6.5% General and Refunding Mortgage Notes, Series O, due 2018 (described above) were used to pay the total consideration for the tender offer on the 10.875% General and Refunding Mortgage Notes, Series E, described below.

General and Refunding Mortgage Notes, Series M

In January 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage Notes, Series M, due March 2016. The Series M Notes were issued with registration rights. In February 2006 the net proceeds of the issuance plus available cash were used to repay $210 million of amounts outstanding under NPC’s revolving credit facility, which were borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Generating Facility.

Revolving Credit Facility

In November 2005, NPC amended and restated its existing secured $350 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility and on the amounts borrowed, increasing the size of the facility to $500 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by at least two of the three rating agencies: Standard & Poor’s (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings Ltd. (“Fitch”). Currently, the base rate is Prime, and NPC’s applicable base rate margin is zero. The Eurodollar margin is 0.75%.

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In April 2006, NPC increased the size of the credit facility to $600 million. The facility provides additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2007, NPC had $4.9 million of letters of credit outstanding and had no borrowings outstanding under the revolving credit facility. As of February 22, 2008, NPC had $5.1 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility.

The NPC Credit Agreement contains 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, 2007, 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.

Other Redemptions

General and Refunding Mortgage Notes, Series G

In June 2007, NPC settled its cash tender offer for its 9.00% General and Refunding Mortgage Notes, Series G, due 2013. Those holders who tendered their notes were entitled to receive a purchase price of $1,079.75 per $1,000 principal amount of Series G Notes. Approximately $210.3 million of the $227.5 million Series G Notes outstanding were validly tendered and accepted by NPC. As of December 31, 2007, approximately $17.2 million aggregate principal amount of the 9.00% General and Refunding Mortgage Bonds remain outstanding.

In July 2005, NPC redeemed $122.5 million aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013. This redemption constituted 35% of the principal amount outstanding. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt.

Sierra Pacific Power Company

6.75% General and Refunding Mortgage Notes, Series P

On June 28, 2007, SPPC issued and sold $325 million of its 6.750% General and Refunding Mortgage Notes, Series P, due July 1, 2037. The Series P Notes were issued pursuant to a registration statement previously filed with the Securities and Exchange Commission. The net proceeds from the issuance were used to fund the purchase of the tendered Series A Notes (discussed below), repay amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Washoe County Water Facilities Refunding Revenue Bonds

On April 27, 2007, on behalf of SPPC, Washoe County, Nevada (Washoe County) issued $80 million aggregate principal amount of its Water Facilities Refunding Revenue Bonds, Series 2007A and B, due March 1, 2036 (the “Water Bonds”).

In connection with the issuance of the Water Bonds, SPPC entered into financing agreements with Washoe County, pursuant to which Washoe County loaned the proceeds from the sales of the Water Bonds to SPPC. SPPC’s payment obligations under the financing agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series O.

The Water Bonds initial rates, as determined by auction on April 25, 2007, were 3.85%. The method of determining the interest rate on the Water Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.

The proceeds of the offerings were used to refund the $80 million aggregate principal amount of 5.00% Washoe County Water Facilities Revenue Bonds, Series 2001.

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Pollution Control and Gas and Water Facilities Refunding Revenue Bonds, Series 2006, 2006A, 2006B and 2006C

In November 2006, on behalf of SPPC, Humboldt County, Nevada (Humboldt County) issued $49.75 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due October 2029. On the same date, on behalf of SPPC, Washoe County, Nevada (Washoe County) issued $58.7 million aggregate principal amount of it Gas Facilities Refunding Revenue Bonds, Series 2006A, due August 2031; $75 million aggregate principal amount of its Water Facilities Refunding Revenue Bonds, Series 2006B, due March 2036; and $84.8 million aggregate principal amount of its Gas and Water Facilities Refunding Revenue Bonds, Series 2006C, due March 2036.

In connection with the issuance of these Bonds, SPPC entered into financing agreements with Humboldt County and Washoe County, pursuant to which Humboldt County and Washoe County loaned the proceeds from the sales of the bonds to SPPC. SPPC’s payment obligations under the financing agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series N.

The proceeds of the offerings were used to refund the following, all of which were previously issued for the benefit of SPPC:

	•		$17.5 million principal amount of 6.65% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1987

	•		$20 million principal amount of 6.55% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1990

	•		$21.2 million principal amount of 6.70% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1992

	•		$75 million principal amount of 6.65% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1987

	•		$45 million principal amount of 6.30% Washoe County’s Gas and Water Facilities Refunding Revenue Bonds, Series 1987

	•		$30 million principal amount of 5.90% Washoe County’s Gas and Water Facilities Refunding Revenue Bonds, Series 1993B

	•		$9.8 million principal amount of 5.90% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1993A

	•		$39.5 million principal amount of 6.55% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1987

	•		$10.25 million principal amount of 6.30% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1992A

Humboldt County Pollution Control Refunding Revenue Bonds

In October 2006, the 6.35% Humboldt County Pollution Control Refunding Revenue Bonds, Series 1992B, due August 2022, in the amount of $1 million were redeemed at 100% of the stated principal amount, plus accrued interest.

General and Refunding Mortgage Notes, Series M

In March 2006, SPPC issued and sold $300 million of its 6.00% General and Refunding Mortgage Notes, Series M, due May 2016. The Series M Notes were issued with registration rights. Proceeds of the offering were used to repay $173 million borrowed under the revolving credit facility that was utilized to:

	•		fund the early redemption of $110 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.95% to 8.61% Series A Notes due 2022;

	•		fund the early redemption of $58 million aggregate principal amount of SPPC’s Collateralized Medium Term 7.10% to 7.14% Series B Notes due 2023;

	•		pay for maturing debt of $30 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.81% to 6.83% Series C Notes due 2006;

	•		pay for $51 million in connection with the redemption of $50 million of SPPC’s Series A Preferred Stock (two million shares of stock were redeemed at a redemption price per share of $25.683, plus accrued dividends to the redemption date of $0.4875 per share); and

	•		pay for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.62% to 6.65% Series C Notes due 2006.

Revolving Credit Facility

In November 2005, SPPC amended and restated its existing secured $50 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility, and on the amounts borrowed, increasing the size of the facility to $250 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate, plus a margin that varies based upon SPPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s and Fitch). Currently, the base rate is Prime and SPPC’s applicable base rate margin is zero. The current Eurodollar margin is 0.75%.

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In April 2006, SPPC increased the size of its credit facility to $350 million. The facility provides additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2007, SPPC had $20.5 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility. As of February 22, 2008, SPPC had $19.5 million of letters of credit and had no amounts 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, 2007, 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.

Other Redemptions

Tender Offer for General and Refunding Mortgage Notes, Series A

On June 28, 2007, SPPC settled its cash tender offer, which commenced on June 15, 2007 and expired on June 22, 2007, for its 8.00% General and Refunding Mortgage Notes, Series A, due 2008. Those holders who tendered their notes by the expiration date were entitled to receive a purchase price of $1,022.10 per $1,000 principal amount of Series A Notes. Approximately $220.8 million of the $320 million Series A Notes outstanding were validly tendered and accepted by SPPC. As of December 31, 2007, $99.2 million aggregate principal amount of the 8.00% General and Refunding Mortgage Notes remain outstanding.

Sierra Pacific Resources

Debt Repurchase

In December 2007, SPR repurchased approximately $10.5 million of the 7.803% Senior Notes and approximately $14.5 million of the 6.75% Senior Notes. The total consideration was approximately $26 million (which included a premium and accrued interest), and was paid from SPR’s cash on hand. As of December 31, 2007, the outstanding balances for the 7.803% Senior Notes and 6.75% Senior Notes were $63.7 million and $210.5 million, respectively.

Tender Offer

In November 2006, SPR commenced tender offers for up to $110 million aggregate principal amount of its 7.803% Senior Notes due 2012, its 8.625% Senior Notes due 2014, and its 6.75% Senior Notes due 2017. Each of the offers was conditioned on SPR purchasing no more than an aggregate principal amount of $110 million of all notes validly tendered. To meet this condition, SPR terminated the offer for the 6.75% Notes. In December 2006 approximately $25 million of the 7.803% Senior Notes outstanding, and approximately $85 million of the 8.625% Senior Notes outstanding were validly tendered and accepted by SPR. The total consideration paid was approximately $120.6 million (which included an early tender premium and accrued interest).

7.803% Senior Notes

In May 2005, SPR issued $99.1 million aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the Premium Income Equity Securities (Old PIES), which were originally issued in November 2001. SPR successfully remarketed these notes in June 2005. In connection with the remarketing, the interest rate of the senior notes was reset to 7.803% per annum, effective on and after June 14, 2005. The remarketed senior notes will mature in June 2012. In December 2006, a portion of these Notes were tendered. (See Tender Offer and Debt Repurchase above).

6.75% Senior Notes

In August 2005, SPR conducted a private placement of $225 million 6.75% Senior Notes due 2017. The proceeds were used to repurchase approximately $141 million 7.93% Senior Notes associated with the Old PIES, pay approximately $54 million in premiums associated with the conversion of the 7.25% Notes and fund the associated fees and expenses; and to provide additional liquidity to SPR. (See Debt Repurchase above).

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8.625% Senior Notes

In March 2004, SPR issued and sold $335 million 8.625% Senior Unsecured Notes due March 2014. The Senior Unsecured Notes, which were issued with registration rights, were exchanged for registered notes in October 2004. The proceeds of the issuance were used to fund the repurchase of approximately $174 million in principal amount of SPR’s 8.75% Notes due 2005 at a price equal to approximately 107.225% of the principal amount thereof that were tendered pursuant to SPR’s tender offer.

The balance of the net proceeds were used in May 2004 to legally extinguish the approximately $126 million of remaining principal amount of SPR’s 8.75% Notes due 2005 which were not tendered, and to pay associated interest and fees and expenses associated with the tender offer and the Notes offering. The total cost to extinguish the debt was approximately $23.7 million consisting of tender fees, interest costs and unamortized debt issuance costs.

In December 2006, a portion of the 8.625% Senior Unsecured Notes were tendered (See Tender Offer above). As of December 31, 2007, $250 million aggregate principal amount of the 8.625% Senior Notes remain outstanding.

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 Southern Operations Center. In accordance with SFAS 13, “Accounting for Leases”, 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 has not begun depreciating the property as it continues to construct leasehold improvements. NPC expects to transfer operations to the facilities in or around mid summer 2008. 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.

Minimum lease payments for capital leases as of December 31, 2007, were as follows (dollars in thousands):


2008	$	13,147
2009		12,467
2010		12,466
2011		9,630
2012		9,493
Thereafter		42,178

Total minimum lease payments	$	99,381

Less amounts representing interest	$	37,950


Present value of net minimum lease payments	$	61,431

NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2007, 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 NPC’s consolidated long-term debt at December 31, 2007, is estimated to be $2.6 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 $2.5 billion at December 31, 2006.

The total fair value of SPPC’s consolidated long-term debt at December 31, 2007, is estimated to be $1.2 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 $1.1 billion as of December 31, 2006.

The total fair value of SPR’s consolidated long-term debt at December 31, 2007 is estimated to be $4.3 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPR for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $4.1 billion as of December 31, 2006.

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NOTE 8.		DEBT COVENANT AND OTHER RESTRICTIONS

Dividends from Subsidiaries

Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. In 2007, NPC and SPPC paid $28.2 million and $14.2 million in dividends, respectively, to SPR. In January 2008, NPC and SPPC paid $10.8 million and $5.3 million, respectively, in dividends declared prior to December 31, 2007.

On February 8, 2008, NPC and SPPC declared a $14.0 million and $8.0 million dividend, respectively, to SPR, to be paid in March 2008.

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. In June 2007, the PUCN terminated the dividend restriction previously imposed by the PUCN in February 2006, which limited the combined amount of cash NPC and SPPC could pay to SPR to actual cash necessary to service SPR’s debt for the year.

Certain debt agreements entered into by SPR 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

Sierra Pacific Resources

Dividends are considered periodically by SPR’s Board of Directors and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, SPR’s financial conditions and other matters within the discretion of the Board, as well as dividend restrictions set forth in SPR’s debt. The Board 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 SPR’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 September 2007 and in December 2007, SPR paid a cash dividend of $0.08 per share. In February 2008, SPR declared a cash dividend of $0.08 per share for common stock holders of record as of February 22, 2008. SPR had not paid a dividend since 2002.

Certain SPR debt agreements contain covenants that limit the amount of restricted payments, including dividends that may be made by SPR. However, as of December 31, 2007, SPR complied with all such covenants, and management does not believe that these covenants will materially affect SPR’s ability to pay dividends.

Dividend Restrictions Applicable to the Utilities

Certain series of general and refunding mortgage notes issued by the Utilities contain restrictions on the amount of dividends the Utilities may declare and pay and restrict the circumstances under which such dividends may be declared and paid. However, as of December 31, 2007, the Utilities complied with all such covenants, and these covenants do not currently significantly restrict either Utility’s ability to pay dividends. Although each Utility currently meets the conditions described above, a significant loss by either Utility could cause that Utility to be precluded from paying dividends to SPR until such time as that Utility again meets the coverage test. If the series of notes which contain these covenants are upgraded to investment grade by 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.

The revolving credit agreements of the Utilities contain similar restrictions on the amount of dividends that may be paid. However, those restrictions are currently suspended and will remain suspended so long as the respective Utility’s secured debt is rated investment grade by at least two out of the three major rating agencies.

Additionally, the Utilities are subject to the provision of the Federal Power Act that states that dividends cannot be paid out of funds that are properly included in their capital account. 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 SPR could be jeopardized.

Ability to Issue Debt

Sierra Pacific Resources

Certain debt of SPR places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s 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, 2007, SPR would be allowed to incur up to $1.1 billion of additional indebtedness on a consolidated basis.

129

Notwithstanding this restriction, under the terms of the debt, SPR would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the Utilities’ respective integrated resource plans. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

If the debt containing these covenants 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.

Nevada Power Company

Certain debt of NPC places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC’s 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, 2007, NPC would be allowed to incur $2.5 billion of additional indebtedness. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined debt limit is restricted to the $1.1 billion of additional indebtedness SPR could incur on a consolidated basis.

Under the terms of NPC’s debt, NPC would also be permitted to incur debt, including, but not limited to, obligations incurred to finance property construction or improvements, certain intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to NPC’s 2006 Integrated Resource Plan.

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

Sierra Pacific Power Company

Certain debt of SPPC places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’s 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, 2007, SPPC would be allowed to incur up to $920 million of additional indebtedness on a consolidated basis. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined debt limit is restricted to the $1.1 billion of additional indebtedness SPR could incur on a consolidated basis.

Under the terms of SPPC’s debt, SPPC would also be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvements, certain intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to SPPC’s 2004 Integrated Resource Plan.


NOTE 9.		DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended by SFAS 138, SFAS No. 149 and SFAS No. 155. As amended, SFAS 133 establishes accounting and reporting standards for derivatives instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value. A majority of the contracts entered into by the Utilities meet the criteria specified for this exception.

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. SPR’s and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and marketing of power and the procurement and marketing 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.

130

Interest Rate Risk

In March 2007, SPPC entered into three forward-starting interest rate swap agreements, with an aggregate notional principal amount of $250 million, to manage the risk associated with changes in interest rates and the impact on future interest payments.

In June 2007, SPPC settled its three forward-starting interest rate swap agreements in connection with the issuance of $325 million of its 6.75% fixed rate General and Refunding Mortgage Notes, Series P, due 2037. SPPC received a payment of $11.3 million from the counterparty and recorded the amount as a premium on long term debt to be amortized over the life of the debt in accordance with regulatory accounting practices under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”).

NPC entered into and settled an interest rate lock agreement in June 2007, in connection with the issuance of $350 million of its 6.75% fixed rate General and Refunding Mortgage Notes, Series R, due 2037. NPC made a payment to the counterparty of $546 thousand and recorded the amount as a discount on long term debt to be amortized over the life of the debt in accordance with regulatory accounting practices under SFAS 71.

Risk Management Assets/Liabilities

The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of SPR, NPC and SPPC and the related regulatory assets/liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS 133. The fair values of the open derivative positions are determined using quoted exchange prices, external dealer prices and available market pricing curves. Due to deferred energy accounting treatment under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income (dollars in millions):


	December 31, 2007									December 31, 2006
	Fair Value									Fair Value
	SPR			NPC			SPPC			SPR			NPC			SPPC
Risk management assets — current	$	22.3		$	16.1		$	6.2		$	27.3		$	16.4		$	10.9
Risk management assets - non-current		12.5			9.1			3.4			7.6			5.4			2.2

Total risk management assets		34.8			25.2			9.6			34.9			21.8			13.1

Risk management liabilities- current		39.5			27.0			12.5			123.1			84.7			38.4
Risk management liabilities - non-current		7.4			5.1			2.3			10.8			7.1			3.7

Total risk management liabilities		46.9			32.1			14.8			133.9			91.8			42.1

Less prepaid electric and gas options		13.9			10.2			3.7			23.9			13.9			10.1


Total Risk Management Regulatory (Asset)/Liability - net⁽¹⁾	$	(26.0	)	$	(17.1	)	$	(8.9	)	$	(122.9	)	$	(83.9	)	$	(39.1	)


¹		When amount is negative (loss) it represents a Risk Management Regulatory Asset, when positive (gain) it represents a Risk Management Regulatory Liability.

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 its counterparties and the changes in forward commodity prices. The reduction of risk management liabilities as of December 31, 2007, as compared to December 31, 2006, is mainly due to decrease in option premiums paid in 2007 and favorable open derivative positions on natural gas options held by the Utilities to hedge energy price risk for their customers resulting from higher commodity prices for natural gas at December 31, 2007 relative to contract prices.

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NOTE 10.		INCOME TAXES (BENEFITS)

Sierra Pacific Resources

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


	2007			2006			2005
Provision (benefit) for income taxes
Current
Federal	$	10,503		$	5,914		$	3,159
State		70			—			—

Total current		10,573			5,914			3,159


Deferred
Federal		85,165			144,919			43,833
State		366			494			1,688

Total deferred		85,531			145,413			45,521


Amortization of excess deferred taxes		(2,226	)		(2,315	)		(2,123	)

Amortization of investment tax credits		(6,323	)		(3,407	)		(3,439	)


Total provision for income taxes	$	87,555		$	145,605		$	43,118

Income statement classification of provision (benefit) for income taxes
Operating income	$	75,155		$	91,571		$	39,185
Other income		12,400			54,034			3,933

Total	$	87,555		$	145,605		$	43,118

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):


	2007			2006			2005
Net Income applicable to common stock	$	197,295		$	277,451		$	82,237
Preferred stock dividend requirement		—			2,341			3,900

Subtotal		197,295			279,792			86,137

Total income tax expense (benefit)		87,555			145,605			43,118

Pretax income		284,850			425,397			129,255
Statutory tax rate		35	%		35	%		35	%

Federal income tax expense at statutory rate		99,698			148,889			45,239
Depreciation related to difference in costs basis for tax purposes		2,970			4,709			4,559
Allowance for funds used during construction — equity		(11,133	)		(6,379	)		(7,113	)
Investment tax credit amortization		(6,322	)		(3,407	)		(3,439	)
Goodwill		2,742			2,600			2,230
Research and development credit		(1,130	)		(3,764	)		—
Other — net		730			2,957			1,642

Provision for income taxes before effect of income tax settlements	$	87,555		$	145,605		$	43,118


Effective tax rate		30.7	%		34.2	%		33.3	%

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. The IRS has completed audits of SPR for the years 1997-2004, but Joint Committee on Taxation notification procedures are still pending. SPR 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):


	2007			2006
Deferred income tax assets
Net operating loss and credit carryovers	$	52,925		$	227,834
Employee benefit plans		25,587			71,820
Customer advances		35,044			32,163
Gross-ups received on contribution in aid of construction and customer advances		31,060			31,113
Deferred revenues		4,069			1,586
Reserves		13,743			508
Other		22,232			22,128

Subtotal		184,660			387,152

Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		12,886			15,111
Unamortized investment tax credit		15,559			18,964

Subtotal		28,445			34,075

Total deferred income tax assets before valuation allowance		213,105			421,227
Valuation allowance		(588	)		(732	)

Total deferred income tax assets after valuation allowance	$	212,517		$	420,495


Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	509,161		$	540,338
Deferred energy		88,213			192,653
Regulatory assets		86,517			101,375
Other		70,113			64,791

Subtotal		754,004			899,157
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		267,848			263,170

Total deferred income tax liability	$	1,021,852		$	1,162,327


Net deferred income tax liability	$	569,932		$	512,737
Net deferred income tax liability associated with regulatory matters		239,403			229,095

Total net deferred income tax liability	$	809,335		$	741,832

The total 2006 net deferred income tax liability of $741,832 includes $5,950 of deferred tax liability associated with accumulated depreciation on the Mohave generating station, which, on the financial statements, is included in other regulatory assets.

SPR’s balance sheets contain a net regulatory asset of $239.4 million at December 31, 2007 and $229.1 million at December 31, 2006. The regulatory 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 SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory 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 credit.

As reflected in SPR’s balance sheet (dollars in thousands):


	2007		2006
Tax benefits flowed through to customers
Related to property	$	115,045	$	106,175
Related to goodwill		152,803		156,995

Regulatory tax asset		267,848		263,170


Liberalized depreciation at rates in excess of current rates		12,886		15,111
Unamortized investment tax credits		15,559		18,964

Regulatory tax liability		28,445		34,075

Net regulatory tax asset	$	239,403	$	229,095

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

The following table summarizes as of December 31, 2007 the tax NOL and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which SPR has determined that realization is uncertain (dollars in thousands):

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	Deferred				Net
	Tax		Valuation		Deferred		Expiration
	Asset		Allowance		Tax Asset		Period
Federal NOL	$	20,992	$	—	$	20,992		2020-2023
State NOLs		127		—		127		2008-2013

Research and development credit		5,465				5,465		2021-2025
Alternative minimum tax credit		25,241		—		25,241	indefinite
Arizona coal credits		1,100		588		512		2008-2012

Total	$	52,925	$	588	$	52,337

At December 31, 2007, SPR has gross federal and state net operating loss carry-forwards of $60.0 million and $1.4 million, respectively.

Considering all positive and negative evidence regarding the utilization of SPR’s deferred tax assets, it has been determined that SPR 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, 2007.

SPR and the Utilities adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”) as of January 1, 2007. As a result of the implementation of FIN 48, SPR and the Utilities recognized approximately a $27.8 million increase in the liability for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (dollars in thousands):


Balance at January 1, 2007	$	27,766
Additions based on tax positions related to the current year		9,487
Additions for tax positions of prior years		5,052
Reductions for tax positions of prior years		(17,289	)
Settlements		—
Lapse of statute of limitations		—

Balance at December 31, 2007	$	25,016

SPR 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, 2007 is $25.0 million, of which $2.4 million would affect the effective tax rate if recognized. No interest or penalties have been accrued as of December 31, 2007. No significant increases or decreases to unrecognized tax benefits are expected within the next twelve months.

SPR and the Utilities file a consolidated U.S. federal income tax return. The U.S. federal jurisdiction is the only “significant” tax jurisdiction for the Company. In connection with the previous examination cycles, the statute of limitations for tax years 1997 through 2003 was extended to December 31, 2008. The audits of tax years 1997 through 2004 have been completed, but are pending Joint Committee on Taxation notification. Tax years 2004-2007 remain subject to federal tax examination. All earlier years are closed by statute.

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Nevada Power Company

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


	2007			2006			2005
Provision (benefit) for income taxes
Current
Federal	$	25,351		$	4,865		$	3,159
State		—			—			—

Total current		25,351			4,865			3,159


Deferred
Federal		58,344			114,741			63,873
State		(63	)		268			(449	)

Total deferred, net		58,281			115,009			63,424


Amortization of excess deferred taxes		(1,236	)		(745	)		(778	)

Amortization of investment tax credits		(4,044	)		(1,619	)		(1,810	)


Total provision for income taxes	$	78,352		$	117,510		$	63,995


Income statement classification of provision for income taxes
Operating income	$	61,108		$	91,781		$	46,425
Other income		17,244			25,729			17,570

Total	$	78,352		$	117,510		$	63,995

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):


	2007			2006			2005
Net income	$	165,694		$	224,540		$	132,734
Total income tax expense		78,352			117,510			63,995

Pretax income		244,046			342,050			196,729
Statutory tax rate		35	%		35	%		35	%

Federal income tax expense at statutory rate		85,416			119,718			68,855
Depreciation related to difference in cost basis for tax purposes		1,291			2,192			1,880
Allowance for funds used during construction — equity		(5,551	)		(4,114	)		(6,539	)
Investment tax credit amortization		(4,044	)		(1,619	)		(1,810	)
Goodwill		1,732			1,646			1,386
Research and development credit		(527	)		(1,666	)		—
Other — net		35			1,353			223

Provision for income taxes before effect of income tax settlements	$	78,352		$	117,510		$	63,995


Effective tax rate		32.1	%		34.4	%		32.5	%

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. The IRS has completed audits of NPC for the years 1997-2004, but Joint Committee on Taxation notification procedures are still pending. NPC believes that it has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.

135

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


	2007			2006
Deferred income tax assets
Net operating loss and credit carryovers	$	26,341		$	137,344
Employee benefit plans		13,940			29,997
Customer advances		20,611			21,014
Gross-ups received on contributions in aid of construction and customer advances		21,334			21,844
Deferred revenues		1,948			1,586
Reserves		10,633			(4	)
Other — net		12,928			14,207

Subtotal		107,735			225,988

Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		4,024			5,259
Unamortized investment tax credit		6,014			8,192

Subtotal		10,038			13,451

Total deferred income tax assets before valuation allowance		117,773			239,439
Valuation allowance		(588	)		(732	)

Total deferred income tax assets after valuation allowance	$	117,185		$	238,707


Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	319,926		$	345,135
Deferred energy		98,342			171,113
Regulatory assets		65,038			59,092
Other — net		51,407			43,299

Subtotal		534,713			618,639
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		165,257			153,471

Total deferred income tax liability	$	699,970		$	772,110


Net deferred income tax liability	$	427,566		$	393,383
Net deferred income tax liability associated with regulatory matters		155,219			140,020

Total net deferred income tax liability	$	582,785		$	533,403

The total 2006 net deferred income tax liability of $533,403 includes $5,950 of deferred tax liability associated with accumulated depreciation on the Mohave generating station, which, on the financial statements, is included in other regulatory assets. Reference Note 1, Summary of Significant Accounting Policies, for further discussion of the Mohave Generating Station.

NPC’s balance sheet contains a net regulatory asset of $155.2 million at December 31, 2007 and $140.0 million at December 31, 2006. The regulatory 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 SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory 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 credit.

As reflected in NPC’s balance sheet (dollars in thousands):


	2007		2006
Tax benefits flowed through to customers
Related to property	$	69,602	$	55,177
Related to goodwill		95,655		98,294

Regulatory tax asset		165,257		153,471


Liberalized depreciation at rates in excess of current rates		4,024		5,259
Unamortized investment tax credits		6,014		8,192

Regulatory tax liability		10,038		13,451

Net regulatory tax asset	$	155,219	$	140,020

136

The following table summarizes as of December 31, 2007 the NOL and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NPC has determined that realization is uncertain (dollars in thousands):


	Deferred		Valuation		Deferred		Expiration
Type of Carryforward	Tax Asset		Allowance		Tax Asset		Period
Alternative minimum tax credit	$	25,241	$	—	$	25,241	indefinite
Arizona coal credits		1,100		588		512		2008-2012

Total	$	26,341	$	588	$	25,753

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, 2007.

SPR and the Utilities adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”) as of January 1, 2007. As a result of the implementation of FIN 48, Nevada Power Company recognized approximately a $6.8 million increase in the liability for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits for Nevada Power Company is as follows (dollars in thousands):


Balance at January 1, 2007	$	6,784
Additions based on tax positions related to the current year		8,918
Additions for tax positions of prior years		4,989
Reductions for tax positions of prior years		(562	)
Settlements		—
Lapse of statute of limitations		—

Balance at December 31, 2007	$	20,129

SPR 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 Nevada Power Company as of December 31, 2007, is $20.1 million, of which $0.9 million would affect the effective tax rate if recognized. No interest or penalties have been accrued as of December 31, 2007. No significant increases or decreases to unrecognized tax benefits are expected within the next twelve months.

137

Sierra Pacific Power Company

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


	2007			2006			2005
Provision (benefit) for income taxes
Current
Federal	$	57,483		$	28,497		$	67,291
State		70			—			—

Total current		57,553			28,497			67,291


Deferred
Federal		(28,705	)		2,464			(38,074	)
State		429			226			2,136

Total deferred		(28,276	)		2,690			(35,938	)


Amortization of excess deferred taxes		(990	)		(1,570	)		(1,345	)

Amortization of investment tax credits		(2,278	)		(1,788	)		(1,629	)


Total provision for income taxes	$	26,009		$	27,829		$	28,379


Income statement classification of provision (benefit) for income taxes
Operating income	$	29,991		$	23,570		$	26,038
Other income		(3,982	)		4,259			2,341

Total	$	26,009		$	27,829		$	28,379

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):


	2007			2006			2005
Income from continuing operations	$	65,667		$	57,709		$	52,075
Total income tax expense (benefits)		26,009			27,829			28,379

Pretax income		91,676			85,538			80,454
Statutory tax rate		35	%		35	%		35	%

Federal income tax expense (benefit) at statutory rate		32,087			29,938			28,159
Depreciation related to difference in cost basis for tax purposes		1,679			2,517			2,678
Allowance for funds used during construction — equity		(5,582	)		(2,265	)		(574	)
Investment tax credit amortization		(2,278	)		(1,788	)		(1,629	)
Goodwill		1,009			954			844
Research and development credit		(603	)		(2,097	)		—
Other — net		(303	)		570			(1,099	)

Provision for income taxes	$	26,009		$	27,829		$	28,379

Effective tax rate		28.4	%		32.5	%		35.3	%

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. The IRS has completed audits of SPPC for the years 1997-2004, but Joint Committee on Taxation notification procedures are still pending. SPPC believes that it has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.

138

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


	2007		2006
Deferred income tax assets
Net operating loss and credit carryforwards	$	5,311	$	6,233
Employee benefit plans		8,327		39,191
Customer advances		14,432		11,149
Gross-ups received on contributions in aid of construction and customer advances		9,726		9,269
Deferred revenues		2,121		—
Deferred energy		10,130		—
Reserves		2,903		200
Other		9,034		7,761

Subtotal		61,984		73,803

Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		8,862		9,852
Unamortized investment tax credit		9,545		10,772

Subtotal		18,407		20,624

Total deferred income tax assets	$	80,391	$	94,427


Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	189,234	$	195,203
Deferred energy		—		21,540
Regulatory assets		20,446		41,346
Other		18,192		14,035

Subtotal deferred tax liabilities		227,872		272,124
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		102,591		109,699

Total deferred income tax liability	$	330,463	$	381,823


Net deferred income tax liability	$	165,889	$	198,321
Net deferred income tax liability associated with regulatory matters		84,184		89,075

Total net deferred income tax liability	$	250,073	$	287,396

SPPC’s balance sheet contains a net regulatory asset of $84.2 million at December 31, 2007 and $89.0 million at December 31, 2006. The regulatory 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 SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory 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 credit.

As reflected in SPPC’s balance sheet (dollars in thousands):


	2007		2006
Tax benefits flowed through to customers
Related to property	$	45,443	$	50,998
Related to goodwill		57,148		58,701

Regulatory tax asset		102,591		109,699


Liberalized depreciation at rates in excess of current rates		8,862		9,852
Unamortized investment tax credits		9,545		10,772

Regulatory tax liability		18,407		20,624

Net regulatory tax asset	$	84,184	$	89,075

139

The following table summarizes as of December 31, 2007 the NOL and tax credit carryovers and associated carryover periods for SPPC (dollars in thousands):


					Net
	Deferred		Valuation		Deferred		Expiration
Type of Carryforward	Tax Asset		Allowance		Tax Asset		Period
Federal NOL	$	5,184	$	—	$	5,184		2020-2023
State NOL		127		—		127		2010-2013

Total	$	5,311	$	—	$	5,311

At December 31, 2007, SPPC has gross federal and state net operating loss carryforwards of $14.8 million and $1.4 million, respectively.

Considering all positive and negative evidence regarding the utilization of SPPC’s deferred tax assets, it has been determined that the company is more-likely-than-not to realize all recorded deferred tax assets and therefore no valuation allowance has been recorded as of December 31, 2007.

SPR and the Utilities adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”) as of January 1, 2007. As a result of the implementation of FIN 48, Sierra Pacific Power Company recognized approximately a $4.4 million increase in the liability for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits for Sierra Pacific Power Company is as follows (dollars in thousands):


Balance at January 1, 2007	$	4,403
Additions based on tax positions related to the current year		569
Additions for tax positions of prior years		—
Reductions for tax positions of prior years		(542	)
Settlements		—
Lapse of statute of limitations		—

Balance at December 31, 2007	$	4,430

SPR 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 Sierra Pacific Power Company as of December 31, 2007 is $4.4 million, of which $1.1 million would affect the effective tax rate if recognized. No interest or penalties have been accrued as of December 31, 2007. No significant increases or decreases to unrecognized tax benefits are expected within the next twelve months.

140

NOTE 11. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

SPR has pension plans covering substantially all employees. Benefits are based on years of service and the employee’s highest compensation for a period prior to retirement. SPR also has other postretirement plans which provide medical and life insurance benefits for certain retired employees. The following tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans. This reconciliation is based on a September 30 measurement date (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2007			2006			2007			2006
Change in benefit obligations
Benefit obligation, beginning of year	$	645,373		$	625,451		$	172,192		$	179,184
Service cost		22,901			23,033			2,680			3,533
Interest cost		39,420			36,627			10,088			10,283
Plan Participants’ contributions		—			—			2,044			1,445
Actuarial loss (gain)		(8,414	)		(18,414	)		6,382			(10,770	)
Gross Benefits paid		(31,949	)		(20,960	)		(10,031	)		(11,998	)
less: federal subsidy on benefits paid		N/A			N/A			596			515
Administrative Expenses		(328	)		(299	)		—			—
Plan amendments		—			(65	)		(28,804	)		—
Plan amendments — Local 1245 Buy Down		—			—			(12,600	)		—
Utility Discount adjustment		—			—			6,545			—
Death Benefit Obligation adjustment		—			—			1,083			—
Acquisitions/divestitures		—			—						—
Special Termination Benefits		—			—			—			—
Curtailments		—			—			—			—
Settlements		7,684			—			—			—

Benefit obligation, end of year	$	674,687		$	645,373		$	150,175		$	172,192

The accumulated benefit obligation for Pension Benefits at the end of 2007 and 2006 was $545 million and $526 million respectively.

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


							Other Postretirement
	Pension Benefits						Benefits
	2007			2006			2007			2006
Discount rate		6.30	%		6.00	%		6.25	%		6.00	%
Rate of compensation increase		4.50	%		4.50	%		N/A			N/A

In 2007, for measurement purposes, the assumed annual rate of increase in the per capita cost of covered health care benefits was 8%, grading down to 5% in 2014.

In selecting an assumed discount rate for fiscal year 2007 pension cost and for fiscal year-end 2007 disclosures, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.

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	2007			2006
Effect of a 1-percentage point increase	$	9,860		$	18,823
Effect of a 1-percentage point decrease	$	(8,538	)	$	(15,657	)

141

The following table shows the change in plan assets for 2007 and 2006. SPR contributions for other post-retirement benefits reflect funding and benefit payments made by SPR (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2007			2006			2007			2006
Change in plan assets
Fair value of plan assets, beginning of year	$	534,260		$	488,766		$	63,236		$	53,223
Adjustment to beginning of year value		—			—			—			—
Actual return on plan assets		73,483			34,424			7,613			8,015
Employer contributions		64,529			32,329			46,059			12,550
Plan participants’ contributions		—			—			2,044			1,445
Gross benefits paid		(31,949	)		(20,960	)		(10,031	)		(11,998	)
Acquisitions		—			—			—			—
Special termination benefits		—			—			—			—
Settlements		—			—			—			—
Expenses paid		(327	)		(299	)		—			—

Fair value of plan assets, end of year	$	639,996		$	534,260		$	108,921		$	63,235

The asset allocation for SPR’s pension plans at the end of 2007 and 2006, and the target allocation for 2008, by asset category, follows. The fair value of plan assets for these plans is $640 million and $534.2 million, at the end of 2007 and 2006, respectively. The expected long-term rate of return on these plan assets was 8.00% and 8.25% in 2007 and 2006, respectively.


	Allocation Percentage of Plan Assets at Year End
	2008			2007			2006
Asset Category
Equity securities		60	%		60	%		60	%
Debt securities		40	%		40	%		39	%
Other		—			—			1	%

Total		100	%		100	%		100	%

The asset allocation for the other postretirement benefit plans at the end of 2007 and 2006, and target allocation for 2008, by asset category, follows. The fair value of plan assets for these plans is $108.9 million and $63.2 million at the end of 2007 and 2006, respectively. The asset values are determined using recorded closing sales on a national securities exchange. The expected long-term rate of return on these plan assets was 8.00% and 8.25% in 2007 and 2006, respectively.


	Allocation Percentage of Plan Assets at Year End
	2008			2007			2006
Asset Category
Equity securities		60	%		60	%		60	%
Debt securities		40	%		40	%		39	%
Other		—			—			1	%

Total		100	%		100	%		100	%

SPR’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. SPR strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets. Also, SPR 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. SPR’s investment guidelines prohibit investing the plan assets in real estate and SPR’s own stock. Currently, the plan assets are invested in international and domestic equity securities, and fixed securities which include bonds.

The pension plan assets and other post retirement benefit assets included approximately $255 million and $37 million, respectively, of debt securities at year end. The majority of the debt securities are valued on either a mark to matrix or a mark to model basis. The value of these assets is determined by independent pricing services on behalf of asset managers. In the case of debt securities in the pension plan assets, the custodian also uses independent pricing services to verify the managers’ valuation. Differences are reconciled on a monthly basis. The plan assets do not have significant exposure to sub prime mortgages.

142

The following table shows the funded status of each of the plans for 2007 and 2006 (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2007			2006			2007			2006
Funded Status, end of year:
Fair value of plan assets	$	639,996		$	534,260		$	108,921		$	63,236
Benefit obligations		(674,687	)		(645,373	)		(150,175	)		(172,192	)

Funded status	$	(34,691	)	$	(111,113	)	$	(41,254	)	$	(108,956	)
Unrecognized net actuarial (gain)/loss		—			—			—			—
Unrecognized prior service (credit)/cost		—			—			—			—
Unrecognized net transition (asset)/obligation		—			—			—			—
Contribution between measurement date and fiscal year end		337			368			—			—

Amount recognized, end of year	$	(34,354	)	$	(110,745	)	$	(41,254	)	$	(108,956	)

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


							Other Postretirement
	Pension Benefits						Benefits
	2007			2006			2007			2006
Amounts recognized in the balance sheet consist of:
Noncurrent asset	$	—		$	—		$	—		$	—
Current liability		(6,381	)		(1,482	)		—			—
Noncurrent liability		(27,973	)		(109,263	)		(41,254	)		(108,956	)
Prepaid benefit cost		—			—			—			—
Accrued benefit cost		—			—			—			—
Additional minimum liability		—			—			—			—
Intangible asset		—			—			—			—
Accumulated other comprehensive income		—			—			—			—

Net amount recognized	$	(34,354	)	$	(110,745	)	$	(41,254	)	$	(108,956	)

The following amounts would have been recognized in Accumulated Other Comprehensive Income, net of taxes, according to the provisions of SFAS 158, which the Company adopted in 2006. Since the Company is able to recover SFAS 87 and SFAS 106 expenses through rates, the amounts will be recorded as regulatory assets for pension plans under the provisions of SFAS 71.


					Other Postretirement
	Pension Benefits				Benefits
	2007		2006		2007			2006
Amounts recognized in regulatory assets for pension plans:
Net actuarial (gain)/loss	$	95,800	$	101,674	$	61,136		$	102,413
Prior service (credit)/cost		10,958		12,587		(33,910	)		1,107
Transition (asset)/obligation		—		—		—			5,436

	$	106,758	$	114,261	$	27,226		$	108,956

The estimated amounts that will be amortized from other regulatory assets and accumulated other comprehensive income into net periodic cost in 2008 are as follows:


			Other
			Postretirement
	Pension Benefits		Benefits
Actuarial (gain)/loss	$	4,747	$	4,596
Prior service (credit)/cost		2,040		(3,830	)
Transition (asset)/obligation		—		—

143

At the end of 2007 and 2006, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with a projected benefit obligation in excess of plan assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):


	Projected Benefit				Accumulated Benefit
	Obligation Exceeds				Obligation Exceeds
	the Fair Value of				the Fair Value of
	Plan's Assets				Plan's Assets
	2007		2006		2007		2006
Projected benefit obligation, end of year	$	674,687	$	645,373	$	20,660	$	25,890
Accumulated benefit obligation, end of year		—		—		18,583		23,768
Fair value of plan assets, end of year		639,996		534,260		—		—

The accumulated postretirement benefit obligation exceeds plan assets for all of the company’s other postretirement benefit plans.

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


	Pension		Other Postretirement
	Benefits		Benefits
Company contributions
2008 (expected)	$	1,881	$	352
					Expected
					Federal
			Gross		Subsidy
Expected benefit payments
2008		25,890		8,405		283
2009		26,897		9,113		306
2010		28,807		9,577		324
2011		31,040		10,134		332
2012		33,527		10,592		341
2013-2017		215,141		58,841		1,749

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.

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

Sierra Pacific Resources, consolidated


	Pension Benefits									Other Postretirement Benefits
	2007			2006			2005			2007			2006			2005
Service cost	$	22,901		$	23,033		$	18,481		$	2,680		$	3,533		$	3,281
Interest cost		39,420			36,627			32,248			10,088			10,283			9,858
Expected return on plan assets		(41,895	)		(40,729	)		(36,167	)		(5,182	)		(4,919	)		(3,862	)
Amortization of:
Actuarial (gain)/loss		7,211			9,778			6,454			3,413			4,614			3,782
Prior service (credit)/cost		1,629			1,892			1,714			(225	)		122			63
Transition (asset)/obligation		—			—			—			484			969			969
Curtailment (gain)/loss		—			—			—			—			—			—
Settlement (gain)/loss / Special termination charges		4,441			—			723			—			—			11

Total net benefit cost	$	33,707		$	30,601		$	23,453		$	11,258		$	14,602		$	14,102

144

The average percentage of SPR net periodic costs capitalized during 2007, 2006 and 2005 was 34.7%, 35.5% and 34.1%, respectively.

Nevada Power Company


	Pension Benefits									Other Postretirement Benefits
	2007			2006			2005			2007			2006			2005
Service cost	$	13,092		$	12,900		$	10,328		$	1,079		$	1,052		$	887
Interest cost		18,977			17,466			15,064			2,178			2,105			1,977
Expected return on plan assets		(19,000	)		(18,265	)		(16,025	)		(1,232	)		(1,079	)		(832	)
Amortization of:
Actuarial (gain)/loss		—			—			—			729			940			758
Prior service (credit)/cost		1,430			1,677			1,499			606			122			63
Transition (asset)/obligation		3,429			4,636			2,995			485			969			969
Curtailment (gain)/loss		—			—			—			—			—			—
Settlement (gain)/loss / Special termination charges		—			—			723			—			—			11

Total net benefit cost	$	17,928		$	18,414		$	14,584		$	3,845		$	4,109		$	3,833

The average percentage of NPC net periodic costs capitalized during 2007, 2006 and 2005 was 38.8%, 39.0% and 37.3%, respectively.

Sierra Pacific Power Company


	Pension Benefits									Other Postretirement Benefits
	2007			2006			2005			2007			2006			2005
Service cost	$	8,553		$	8,989		$	7,470		$	1,542		$	2,417		$	2,264
Interest cost		19,100			18,224			16,526			7,844			8,114			7,793
Expected return on plan assets		(21,969	)		(21,617	)		(19,418	)		(3,823	)		(3,715	)		(2,929	)
Amortization of:
Actuarial (gain)/loss		—			—			—			2,663			3,646			2,994
Prior service (credit)/cost		212			212			212			(831	)		—			—
Transition (asset)/obligation		3,467			4,880			3,320			—			—			—
Curtailment (gain)/loss		—			—			—			—			—			—
Settlement (gain)/loss / Special termination charges		—			—			—			—			—			—

Total net benefit cost	$	9,363		$	10,688		$	8,110		$	7,395		$	10,462		$	10,122

The average percentage of SPPC net periodic costs capitalized during 2007, 2006 and 2005 was 35.7%, 33.3% and 32.1%, respectively.

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


	Pension Benefits									Other Postretirement Benefits
	2007			2006			2005			2007			2006			2005
Discount rate		6.00	%		5.75	%		6.10	%		6.00	%		5.75	%		6.10	%
Expected Return on Plan Assets		8.00	%		8.25	%		8.25	%		8.00	%		8.25	%		8.25	%
Rate of compensation increase		4.50	%		4.50	%		4.50	%		N/A			N/A			N/A

For measurement purposes, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2007. The rate was assumed to average to 5% in all future years.

The expected rate of return 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 rates of return on reinvested assets.

The expected long-term rate of return on plan assets is 8.00% in 2008.

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:	2007			2006			2005
Effect on total of service and interest cost components
Effect of a 1-percentage point increase in health care trend		1,476			1,669			1,872
Effects of a 1-percentage point decrease in health care trend		(1,210	)		(1,360	)		(1,503	)

There were no significant transactions between the plan and the employer or related parties during 2007, 2006, or 2005.

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NOTE 12. STOCK COMPENSATION PLANS

At December 31, 2007, SPR had several stock-based compensation plans, which are described below.

SPR’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 SPR’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 2007, SPR issued nonqualified stock options, restricted shares and performance shares under the long-term incentive plan.

Non-Qualified Stock Options

Elected officers and key employees specifically designated by a committee of the Board of Directors are eligible to be awarded nonqualified 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 also be awarded.

The total number of nonqualifying 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.

A summary of the status of SPR’s nonqualified stock option plan as of December 31, 2007, 2006, and 2005, and changes during the year is presented below:


	2007				2006				2005
			Weighted				Weighted				Weighted
			Average				Average				Average
			Exercise				Exercise				Exercise
Nonqualified Stock Options	Shares		Price		Shares		Price		Shares		Price
Outstanding at beginning of year		1,199,188	$	14.66		1,077,772	$	14.38		1,235,950	$	15.85
Granted		411,036	$	18.25		176,416	$	13.29		169,036	$	10.10
Exercised		312,639	$	14.82		55,000	$	5.69		28,000	$	6.85
Forfeited		3,188	$	19.97		—	$	—		299,214	$	18.73
Outstanding at end of year		1,294,397	$	15.77		1,199,188	$	14.66		1,077,772	$	14.38

Options exercisable at year-end		747,317	$	14.94		913,209	$	15.42		928,368	$	15.07

Intrinsic value of options exercised	$	1,381,976			$	571,190			$	147,240

Fair value of options vested	$	—			$	141,037			$	36,750
Weighted-average grant date fair value of options granted(1):
Average of all grants for:
2007	$	6.27
2006					$	4.82
2005									$	5.52


(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, 2006 and 2005:


							Average
	Average			Average			Risk-Free			Average
	Dividend			Expected			Rate of			Expected
Year of Option Grant	Yield			Volatility			Return			Life
2007		0.00	%		24.23	%		4.41	%	6 years
2006		0.00	%		27.06	%		4.51	%	6 years
2005		0.00	%		39.56	%		2.32	%	10 years

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The following table summarizes information about nonqualified stock options outstanding at December 31, 2007:


			Options Outstanding				Options Exercisable
			Number		Remaining		Weighted		Number Vested and
	Weighted Average		Outstanding at		Contractual		Average		Exercisable at
Year of Grant	Exercise Price		12/31/07		Life		Exercise Price		12/31/07

1998	$	24.93		15,840	<1 year		$	24.93		15,840
1999	$	25.35		36,440	1 year		$	25.35		36,440
2000	$	16.00		400,000	1.6 - 2 years		$	16.00		400,000
2001	$	15.08		22,510	3 years		$	15.08		22,510
2002	$	14.05		86,410	4 - 4.5 years		$	14.05		86,410
2004	$	7.29		25,000	6.5 years		$	7.29		25,000
2005	$	10.10		126,966	7.2 - 7.4 years		$	10.10		87,125
2006	$	13.29		170,195	8.1 years		$	13.29		73,992
2007	$	18.25		411,036	9.1 - 9.8 years		$	18.25		—

Weighted Average Remaining Contractual Life						5.83				3.55

Intrinsic Value	$	2,431,746					$	1,802,651

Dividend equivalents were not granted for any of these awards.

Performance Shares

In 2007, 2006 and 2005, SPR granted performance shares in the following numbers and initial values:


	2/14/2007		2/7/2006		2/7/2005
Shares Granted		138,967		675,056		214,596
Value per Share	$	16.96	$	10.03	$	9.58

In 2007, 2006 and 2005, 138,967, 172,446 and 171,676 shares of stock, respectively, were granted to plan participants; the actual number of shares earned by each participant is dependent upon SPR 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 SPR’s common shares as of the end of the performance periods. Sierra Pacific Resources, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof. In 2007, according to the performance criteria established for each grant, 40,037 shares were deemed to have been earned and were issued.

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 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 is at the discretion of the Board of Directors and the Compensation Committee. In 2007 and 2006, 200,000 and 65,000 shares, respectively, 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.

SPR adopted SFAS No. 123R, “Share Based Payment” (“SFAS 123R”) in 2006, and according to the requirements set forth in that standard, recognized expense in 2007 and 2006 related to performance shares. For purposes of determining expense for those years, the compensation cost has been estimated using a lattice binomial pricing model with the following assumptions used for 2007 and 2006:

147


							Average
	Average			Average			Risk-Free			Weighted
	Dividend			Expected			Rate of			Average
Year	Yield			Volatility			Return			Fair Value
2007		0.00	%		24.87	%		4.77	%	$	17.82
2006		0.00	%		39.03	%		4.57	%	$	13.93
2005		—			—			—			—

The total value of share based liabilities paid in 2007, 2006 and 2005 were $4,362,967, $1,447,300 and $819,117, respectively. The total value of shares vested in 2007, 2006, and 2005 were $2,842,265, $2,046,141 and $881,165, respectively.

Restricted Stock Shares

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.

There were no restricted shares granted in 2005.

In 2004, SPR granted 280,082 performance shares, which were reclassified in 2005 as restricted stock. Due to the achievement of certain performance goals established for this grant, the number of shares available under this grant was increased to 297,587. This grant vested on December 31, 2006, and 237,074 shares were issued in early 2007.

In 2003, SPR granted 438,576 shares of restricted stock at a grant price of $6.60 per share. The shares vested over 4 years with one-third becoming available in each of the years ended December 31, 2004, 2005, and 2006. In early 2007, 111,255 shares were issued under this grant.

The total value of share based liabilities paid in 2007, 2006 and 2005 were $5,957,366, $1,500,321 and $1,405,724, respectively. The total value of shares vested in 2007, 2006 and 2005 were $0, $5,750,643 and $1,596,657, respectively.

Employee Stock Purchase Plan

Upon the inception of SPR’s employee stock purchase plan, SPR was authorized to issue up to an aggregate of 400,162 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 SPR’s common stock. The purchase price of the stock is the lesser of 90% of the market value on the offering commencement date, or 100% 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 SPR sold 56,835, 55,954 and 53,162 shares to employees in 2007, 2006, and 2005, respectively.

SPR adopted SFAS 123R “Share Based Payment” in 2006, and according to the requirements set forth in that standard, recognized expense in 2007 and 2006 related to the employee stock purchase plan. For purposes of determining the expense for 2007 and 2006, and the 2005 pro forma disclosures, 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 2007, 2006 and 2005, with an option life of six months:


							Average
	Average			Average			Risk-Free			Weighted
	Dividend			Expected			Rate of			Average
Year	Yield			Volatility			Return			Fair Value
2007		0.00	%		20.75	%		4.13	%	$	3.02
2006		0.00	%		19.73	%		4.95	%	$	2.62
2005		0.00	%		35.87	%		2.23	%	$	2.65

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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 2008 to 2039. Estimated future commitments under non-cancelable agreements as of December 31, 2007 were as follows (dollars in thousands):


	Purchased Power
	NPC		SPPC		SPR
2008	$	349,322	$	152,428	$	501,750
2009		286,016		123,975		409,991
2010		338,323		167,257		505,580
2011		372,613		190,799		563,412
2012		394,765		203,765		598,530
Thereafter		5,151,777		3,488,879		8,640,656

Coal and Natural Gas

The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2008 to 2018. Estimated future commitments under non-cancelable agreements as of December 31, 2007 were as follows (dollars in thousands):


	Coal and Gas						Transportation
	NPC		SPPC		Total		NPC		SPPC		Total
2008		$222,562		$122,143		$344,705		$42,002		$72,772		$114,774
2009		19,595		22,703		42,298		37,545		65,110		102,655
2010		12,584		16,250		28,834		36,816		44,512		81,328
2011		6,316		16,250		22,566		34,702		44,502		79,204
2012		—		—		—		28,429		44,407		72,836
Thereafter		—		—		—		156,410		295,366		451,776

Long-Term Service Agreements

NPC entered into long-term service agreements for the performance of maintenance on generation units located at the Chuck Lenzie Generation Station and Silverhawk Generation Station. SPPC entered into a long-term service agreement for the Tracy Combined Cycle Plant which is estimated to be operational May 2008. Future commitments under these agreements are as follows (dollars in thousands):


	Long-Term Service Agreements
					Tracy
					Combined
	Silverhawk		Lenzie		Cycle		Total
2008	$	5,886	$	11,258	$	3,106	$	20,250
2009		5,886		11,258		5,325		22,469
2010		5,886		11,258		5,325		22,469
2011		5,886		11,258		5,325		22,469
2012		5,886		11,258		5,325		22,469
Thereafter		23,545		90,062		61,770		175,377

Capital Projects

NPC has entered into agreements for purchase and construction of Clark peaking units. Completion of this project is estimated for second quarter 2008. Additionally, NPC has entered in to a purchase agreement for a turbine for the Harry Allen Combined Cycle project. Estimated completion is 2010. NPC has entered into environmental contracts for upgrading the Clark Units 5-8. Completion of this project is estimated in 2009. A contract for tenant improvements for the Southern Operations Center at NPC is expected to be completed in 2008.

149

SPPC has entered into an agreement for construction of the Tracy Combined Cycle Plant. Estimated completion is 2008. Future commitments under these agreements are as follows (dollars in thousands):


	Capital Projects
	NPC		SPPC		Total
2008	$	190,565	$	6,028	$	196,593
2009		72,425		—		72,425
2010		2,873		—		2,873

Operating Leases

NPC has an operating lease for its Southern Operations Center with a termination date of October 2027. SPPC has an operating lease for its general offices. The primary term of the lease is 25 years, ending 2010. The current annual rental is $5.4 million, which amount remains constant until the end of the primary term. The lease has renewal options for an additional 50 years. In addition, the Utilities entered into master leasing agreements for various equipment.

SPR’s, NPC’s and SPPC’s estimated future minimum cash payments under non-cancelable operating leases as of December 31, 2007, were as follows (dollars in thousands):


	Operating Leases
	NPC		SPPC		Total
2008	$	10,391	$	12,672	$	23,063
2009		9,630		11,605		21,235
2010		8,947		10,682		19,629
2011		6,027		3,329		9,356
2012		4,142		1,557		5,699
Thereafter		33,961		37,452		71,413

Environmental

Nevada Power Company

Reid Gardner Station

Surface and Groundwater Matters

Reid Gardner Station is a coal generating station consisting of four units. Unit no. 4 is co-owned by the California Department of Water Resources (CDWR) 67.8% and 32.2% by NPC. NPC is the operating agent.

Reid Gardner has a number of raw water and scrubber make-up storage ponds as well as ponds used for process water evaporation and fly ash settling. Process water, which has been used beyond the treatable limits, is routed to onsite ponds for evaporation. Waste management units are present throughout the site and surrounding area. Environmental contaminants identified at Reid Gardner 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 Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an order that requires all wastewater 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 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 NDEP Authorization to Discharge Permit issued October 2005.

Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $45 million. Expenditures for 2008 are projected to be approximately $2.8 million, for a total expenditure of approximately $47.8 million.

Over the last two years, the water division of NDEP has been in discussions with NPC regarding what additional surface and groundwater cleanup 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 on Consent (AOC) and the final form of the proposed AOC was delivered to NPC in December 2007. Until such time, NPC did not know the extent of the obligation or scope of work that would be required to effect site restoration due to the complexities associated with environmental remediation of the target media and the evolving standards of acceptable remediation standards. As a result, management was unable to reasonably estimate the cost of this comprehensive remediation project prior to concluding the negotiations and receiving the final AOC from the NDEP.

150

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. The AOC has been designed to supersede previous agreements for remedial activities at the site and takes a comprehensive approach to address historical environmental impacts associated with facility operations. Upon receiving the final document in December 2007, management was able to estimate a range of costs to satisfy the requirements of the AOC. As a result NPC has recorded as an asset retirement obligation in accordance with SFAS 143, Accounting for Asset Retirement Obligations as of December 31, 2007 of approximately $19.8 million, which it expects to receive regulatory recovery of, similar to other Asset Retirement Obligations. Other costs are expected to include capital expenditures and remediation costs of approximately $32.3 million and operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is initiated and additional characterization is completed.

Air Quality Matters

In June 2006, the Environmental Protection Agency (EPA) issued a Finding and Notice of Violation (NOV) related to monitoring, recordkeeping and emission exceedances at the Reid Gardner facility. In April 2007, NPC lodged a Consent Decree in federal district court with NDEP, EPA and the Department of Justice (DOJ) regarding the NOVs and providing for additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that will be required to resolve the alleged violations. Terms of the Consent Decree included a $1.1 million fine, which was paid during 2007, funding of projects, of which NPC expects to spend approximately $2 million for the Supplemental Environmental Project with the Clark County School District, and the installation of emission reduction equipment at the facility. The environmental project is aimed at achieving increased energy efficiency and cost savings for the school district. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations, and which will satisfy the terms of the consent decree, were previously submitted by NPC to the PUCN in NPC’s 2006 IRP filing. 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 $84 million as approved by the PUCN; however, amounts may change depending on the procurement of material and services.

Clark Station

In May 2006, the EPA, by letter from the DOJ, notified NPC that it intended to initiate an enforcement action against NPC seeking unspecified civil penalties, together with injunctive relief, for alleged violations of the Prevention of Significant Deterioration requirements and Title V operating permit requirements of the Clean Air Act at Clark Station. NPC then entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations and in August 2007, a final Consent Decree between NPC and the EPA was entered with the Court. Terms of the Consent Decree include installation of an advanced NOx reduction burner technology on four existing units with an estimated cost of up to $60 million, which cost was previously submitted by NPC to the PUCN in its Second Amendment to the 2006 IRP filing and was approved in May 2007. Additionally, NPC paid a minimal fine and will make a contribution to Vegas Public Broadcasting Service (PBS) to fund a solar panel array on its new Educational Technology Campus planned in Clark County.

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.

Litigation Contingencies

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

Settlement Agreement

On February 1, 2006, the Utilities completed the settlement of long-term, ongoing litigation involving Enron’s market manipulation during the Western United States energy crisis and Enron’s claims with respect to terminated purchase power contracts between Enron Power Marketing Inc. (“Enron”) and the Utilities in accordance with the terms of the Settlement Agreement, entered into as of November 15, 2005 among the Utilities, Enron, and other related Enron affiliates (the “Settlement Agreement”). The Settlement Agreement provided for the settlement and release of the on-going litigation, regulatory proceedings, appellate proceedings, proofs of claim and other claims between Enron and the Utilities related to these matters. The Settlement Agreement received approval from the Enron Bankruptcy Court on December 15, 2005. The FERC’s approval of the Settlement Agreement was received on January 25, 2006, which triggered the mutual releases and discharges of all past, existing and future claims between the parties.

151

On January 26, 2006, upon final approval of the settlement with Enron, the Utilities paid Enron approximately $129 million from available cash resources. On January 27, 2006, the approximate $60 million cash held in escrow, plus interest, and NPC’s General and Refunding Series H Bond of approximately $185.7 million and SPPC’s General and Refunding Series E Bond of approximately $92.3 million were returned to the Utilities. As part of the settlement, NPC and SPPC were granted general unsecured claims (the “Unsecured Claims”) in Class Six of Enron’s Plan of Reorganization in the amount of $80.7 million and $45.8 million, respectively. On October 24, 2005, the Utilities purchased a put option from a major international banking institution that, if exercised, obligated that institution to purchase the Unsecured Claims (contingent upon allowance of the Unsecured Claims by the Bankruptcy Court), which ensured that the Utilities’ net cash outlay to settle Enron’s claim would be no higher than $89.9 million. On February 16, 2006, the Unsecured Claims were sold to a separate third party, resulting in a final net cash outlay which did not materially differ from the anticipated cash outlay.

Nevada Power Company

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station (Navajo Station) which is located in Northern Arizona and is operated by the Salt River Project (Salt River). Other participants in the Navajo 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 (Mohave 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.

Royalty Claim

On October 15, 2004, Navajo 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 Station, Salt River, is defending the suit on behalf of the Navajo Joint Owners. NPC believes Peabody WC’s claims are without merit and intends to contest them. At this time, discovery is ongoing. In October, 2007, the Navajo Joint Owners filed a motion for partial summary judgment against Peabody WC’s claims for reimbursement of attorney fees and indemnification of liability arising out of the DC Lawsuit. In January 2008, Peabody filed responses to the Navajo Joint Owner’s motion. On February 13, 2008, the Navajo Joint Owners filed a second partial summary judgment motion seeking dismissal of another count raised by Peabody concerning indemnity arising out of the DC Lawsuit. The court has yet to rule on both partial summary judgment motions. The case is set for trial in December, 2008. NPC is unable to predict the outcome of this matter or whether any other liability may arise as a result of 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 Station and the Mohave 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 Navajo Station and the Mohave 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 court dismissed all claims against Salt River. The action has been stayed since October 5, 2004. In November, 2007, various parties filed motions to dissolve the stay. The US District Court for the District of Columbia is expected to rule on the motions in the first quarter of 2008.

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 Coal Supply Agreement (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. The RHCC matter is in the early stages of litigation. The FRC claim went to arbitration and parties are in the early process of selecting a panel. Settlement discussions, led by Salt River, are continuous and ongoing. NPC is briefed periodically by Salt River as settlement discussions advance. NPC cannot predict the final outcome of the settlement, but has recorded a $17.4 million liability which management has assessed as the approximate amount to be paid, and a corresponding other regulatory asset for such claims, as management believes that these costs are recoverable through deferred energy.

152

Sierra Pacific Power Company

Farad Dam

SPPC owns four hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (Insurers) for the flume and 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. In May 2005, Insurers filed a motion for summary judgment on the coverage issue, which has been denied. In October 2005, Insurers filed another partial summary judgment motion with respect to coverage, which the court also denied. On June 16, 2006, Insurers filed new summary judgment motions, which SPPC opposed. The Court denied the motions and asked parties to brief the Court on certain insurance coverage issues involving timing and cost recovery associated with rebuilding the dam. The Court reviewed the briefs and set a trial date for April 2008. Management has not recorded a loss contingency for this matter, as the loss, if any, can not be estimated at this time.

Other Legal Matters

SPR 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 Board of Directors of SPR (the Board) voted to amend the Rights Agreement, dated as of February 2001 (as amended and restated, the “Rights Agreement”), between the SPR and Wells Fargo Bank Minnesota, N.A., to accelerate the final expiration date of the rights (“Rights”) issued there under to December 2005, and to terminate the Rights Agreement upon the expiration of the Rights. The Board also adopted a policy governing future entry into a shareholder rights agreement or similar agreement (a “shareholder rights plan”). SPR’s policy is to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the board, 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 SPR’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.

Employee Stock Ownership Plans

As of December 31, 2007, 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 SPR’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.

SPR 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 SPR common stock. The purchase price of the stock is 90% of the market value on the offering date or 100% of the market price on the execution date, if less.

Non-Employee Director Stock

The Non-employee Director Stock Plan provides that a portion of SPR’s outside directors’ annual retainer be paid in SPR common stock. SPR records the costs of these plans in accordance with Accounting Principles Board Opinion No. 25. In addition, in 1996 SPR 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 Board, at the time the Director leaves the Board.

153

The annual retainer for non-employee directors is $70,000, and the minimum amount to be paid in SPR stock is $35,000 per director. During 2007, 2006, and 2005, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 27,300, 30,733, and 31,631 shares, and $280,000, $154,000, and $176,000.

Convertible Notes Issuance

In February 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. In August 2003, SPR obtained shareholder approval to issue additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. In August 2005, SPR announced an offer to pay a cash premium to induce holders to convert their 7.25% Notes to shares of SPR common stock. The conversion offer was accepted by 100% of the holders. In September 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were issued to the holders in exchange for the 7.25% Notes.

In September 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares and an aggregate of $54 million in cash consideration were paid to the holders in exchange for the Convertible Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” the $54 million cash payment was expensed during the third quarter of 2005.

Stock Exchange Transactions

In November 2005 SPR issued 17,344,183 shares of common stock, along with cash in lieu of fractional shares in connection with its PIES. Each PIES consisted of a forward stock purchase contract and a senior unsecured note issued by SPR.

In May 2005, SPR exchanged approximately 41% of the PIES for newly issued PIES (“New PIES”) and issued, as a component of the New PIES $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the PIES. SPR successfully remarketed these notes in June 2005 at an interest rate of 7.803%.

In August 2005, the remaining $141,076,000 aggregate principal amount of its 7.93% Senior Notes associated with the PIES were remarketed. In August 2005, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (see Note 6, Long-Term Debt) to purchase all of the 7.93% Senior Notes.

In November 2005, the purchase contract settlement date for the PIES and New PIES, 3.6101 shares per forward purchase contract were exchanged for a total of 17,344,183 shares of common stock issued to holder of the PIES and New PIES.

Increased Authorized Shares

In May 2006, SPR’s shareholders approved an amendment to SPR’s Restated Articles of Incorporation to increase the number of authorized shares of SPR common stock by 100,000,000 shares for a total amount of 350,000,000 authorized shares.

Common Stock Offering

In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds from the issuance were $280.6 million. In August 2006, SPR contributed capital to NPC of approximately $200 million. NPC used the proceeds to repay indebtedness under its revolving credit facility.

In December 2006, SPR contributed capital to SPPC of approximately $75 million. SPPC used the proceeds to repay indebtedness under its revolving credit facility and general corporate purposes. SPR has invested the remaining proceeds in highly liquid short-term investments pending their use for general corporate purposes.

In December 2007, SPR issued 12 million shares of its $1 par value common stock. Net proceeds from the issuance were $202.8 million. In December 2007, SPR 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, SPR contributed capital to NPC of approximately $53 million and to SPPC of approximately $20 million for general corporate purposes in January 2008.

As of December 31, 2007 SPR has 350 million shares of common stock authorized and approximately 233.7 million shares of common stock issued and outstanding.

154

Dividends

On July 28, 2007, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share paid on September 12, 2007, to common shareholders of record on August 24, 2007. The dividend was the first dividend declared by SPR since February 2002.

On November 1, 2007, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share payable on December 12, 2007, to common shareholders of record on November 19, 2007.

On February 7, 2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share payable on March 12, 2008, to common shareholders of record on February 22, 2008.

155

NOTE 15. EARNINGS PER SHARE (EPS) (SPR)

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

Emerging Issues Task Force, Participating Securities and the Two-Class Method under FASB Statement No. 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive. On September 8, 2005 SPR issued approximately 65.7 million shares of common stock in connection with the early conversion of the 7.25% Convertible Notes. The weighted average shares outstanding up to the date of conversion are shown separately for the year ending December 31, 2005.

On November 15, 2005 the conversion of SPR’s PIES resulted in the issuance of 17.3 million shares. For the year ended December 31, 2005 these shares are included in the denominator on a weighted average basis. See Note 14, Common Stock and Other Paid-In Capital, for discussion of the PIES transaction.

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


	Year ended December 31,
	2007		2006		2005
Basic EPS
Numerator ($000)

Net income applicable to common stock	$	197,295	$	277,451	$	62,198
Net income applicable to convertible notes		—		—		20,039

Net income used for basic calculation	$	197,295	$	277,451	$	82,237


Denominator
Weighted average number of common shares outstanding		222,180,440		208,531,134		140,334,552
Shares from conversion of notes		—		—		45,213,762

		222,180,440		208,531,134		185,548,314


Per Share Amounts
Net income applicable to common stock	$	0.89	$	1.33	$	0.44
Net income applicable to convertible notes	$	—	$	—	$	0.44

Diluted EPS
Numerator ($000)
Net income applicable to common stock	$	197,295	$	277,451	$	82,237


Denominator⁽¹⁾
Weighted average number of shares outstanding before dilution		222,180,440		208,531,134		140,334,552
Stock options		123,124		91,119		47,255
Executive long term incentive plan - restricted		—		113,456		187,810
Non-Employee Director stock plan		46,551		30,754		21,193
Employee stock purchase plan		878		3,345		3,925
Performance Shares		203,031		251,088		124,007
Convertible Stock		—		—		45,213,762

		222,554,024		209,020,896		185,932,504


Per Share Amounts
Net income applicable to common stock	$	0.89	$	1.33	$	0.44


⁽¹⁾		The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the years ended December 31, 2007, 2006, and 2005, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the years ended December 31, 2007, 2006, and 2005, 638,250, 932,946, and 917,623 shares, respectively, would be included.

156

NOTE 16. 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.


	SIERRA PACIFIC RESOURCES
	2007 Quarter Ended
	March		June		September		December
Operating Revenues	$	756,431	$	851,894	$	1,206,050	$	786,585

Operating Income	$	61,930	$	86,431	$	213,137	$	53,069

Net Income Applicable to Common Stock	$	15,607	$	25,754	$	152,222	$	3,712

Net Income Applicable to Common Stock per Share — Basic and Diluted	$	0.07	$	0.12	$	0.69	$	0.02


	2006 Quarter Ended
	March		June		September		December
Operating Revenues	$	707,056	$	821,919	$	1,081,967	$	745,008

Operating Income	$	59,577	$	90,683	$	283,793	$	54,744

Net Income Applicable to Common Stock	$	1,242	$	27,836	$	222,246	$	26,127

Net Income Applicable to Common Stock per Share — Basic and Diluted	$	0.01	$	0.14	$	1.05	$	0.12


⁽¹⁾		In the third quarter of 2006, operating income includes the reinstatement of deferred energy costs of approximately $180 million.


	NEVADA POWER COMPANY
	2007 Quarter Ended
	March		June		September		December
Operating Revenues	$	418,165	$	575,108	$	894,226	$	469,121

Operating Income	$	27,968	$	61,228	$	170,264	$	37,844

Net Income (Loss)	$	4,582	$	23,604	$	133,094	$	4,414


	2006 Quarter Ended
	March			June		September		December
Operating Revenues	$	381,275		$	543,869	$	776,235	$	422,702

Operating Income	$	25,663		$	62,019	$	244,920	$	18,670

Net Income (Loss)	$	(3,296	)	$	28,456	$	211,113	$	(11,733	)


(2)		In the third quarter of 2006, operating income includes the reinstatement of deferred energy costs of approximately $180 million.


	SIERRA PACIFIC POWER COMPANY
	2007 Quarter Ended
	March		June		September		December
Operating Revenues	$	337,999	$	276,734	$	311,818	$	317,746

Operating Income	$	33,911	$	22,213	$	38,118	$	11,715

Net Income	$	21,968	$	10,008	$	25,552	$	8,139

Earnings (Deficit) Applicable to Common Stock	$	21,968	$	10,008	$	25,552	$	8,139


	2006 Quarter Ended
	March		June		September		December
Operating Revenues	$	325,497	$	277,319	$	305,445	$	321,969

Operating Income	$	29,991	$	24,803	$	36,543	$	28,680

Net Income	$	13,272	$	8,999	$	20,028	$	15,410

Earnings Applicable to Common Stock	$	12,297	$	7,633	$	20,028	$	15,410

157

ITEM 9A(T). CONTROLS AND PROCEDURES

Nevada Power Company

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

Although Nevada Power Company 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.

Nevada Power Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, Nevada Power Company used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2007, the Company’s internal control over financial reporting is effective based on those criteria.

Sierra Pacific Power Company

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

Although Sierra Pacific Power Company 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.

158

Sierra Pacific Power Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, Sierra Pacific Power Company used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2007, the Company’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 Nevada Power Company and Sierra Pacific Power Company. The management reports of Nevada Power Company and Sierra Pacific Power Company were not subject to attestation by the independent registered public accountants pursuant to temporary rules of the SEC that permit Nevada Power Company and Sierra Pacific Power Company to provide only management’s reports in their annual report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Sierra Pacific Resources
Reno, Nevada

We have audited the internal control over financial reporting of Sierra Pacific Resources and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued 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 Annual Reports 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, Sierra Pacific Resources and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established inInternal Control — Integrated Frameworkissued 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 schedules as of and for the year ended December 31, 2007 of the Company and our report dated February 27, 2008 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of Statement of Financial Accounting Standards No. 123(R).

DELOITTE & TOUCHE LLP

Reno, Nevada
February 27, 2008

159

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Financial Statement Schedules and Exhibits


		Page
1.	Financial Statements:
	Reports of Independent Registered Public Accounting Firm	86

	Sierra Pacific Resources:
	Consolidated Balance Sheets as of December 31, 2007 and 2006	89
	Consolidated Income Statements for the Years Ended December 31, 2007, 2006 and 2005	90
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2007, 2006 and 2005	91
	Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005	92
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	93
	Consolidated Statements of Capitalization as of December 31, 2006 and 2005	94

	Nevada Power Company:
	Consolidated Balance Sheets as of December 31, 2007 and 2006	96
	Consolidated Income Statements for the Years Ended December 31, 2007, 2006 and 2005	97
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2007, 2006 and 2005	98
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2007, 2006 and 2005	99
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	100
	Consolidated Statements of Capitalization as of December 31, 2007 and 2006	101

	Sierra Pacific Power Company:

	Consolidated Balance Sheets as of December 31, 2007 and 2006	102
	Consolidated Income Statements for the Years Ended December 31, 2007, 2006 and 2005	103
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2007, 2006 and 2005	104
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2007, 2006 and 2005	105
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	106
	Consolidated Statements of Capitalization as of December 31, 2007 and 2006	107

	Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company	108

2.	Financial Statement Schedules:
	Schedule I - Condensed Financial Statements of Sierra Pacific Resources	164
	Schedule II - Consolidated Valuation and Qualifying Accounts	167

	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 169 to 177

162

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company 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.


	SIERRA PACIFIC RESOURCES NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY
	By /s/ William D. Rogers
	William D. Rogers
	Chief Financial Officer (Principal Financial Officer) February 28, 2008

163

SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED BALANCE SHEETS
(Dollars in Thousands)


	December 31,
	2007			2006
ASSETS
Investments and other property, net	$	3,374,387		$	3,045,872

Current Assets:
Cash and cash equivalents		68,250			25,206
Accounts receivable less allowance for uncollectible accounts:
2007 and 2006-$0		52,279			1,755
Current income taxes receivable		17,882			—
Dividends receivable from subsidiary		16,167			20,208
Materials, supplies and fuel, at average cost		13			13
Deferred income taxes		41,130			138
Other		260			420

		195,981			47,740


Deferred Charges and Other Assets:
Goodwill		—			469
Regulatory asset for pension plans		3,297			2,906
Unamortized debt issuance costs		8,690			10,269
Deferred income tax benefit		855			105,010
Other		(4,010	)		1,611

		8,832			120,265


TOTAL ASSETS	$	3,579,200		$	3,213,877


CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	2,996,575		$	2,622,297
Long-term debt		525,173			550,545

		3,521,748			3,172,842


Current Liabilities:
Accounts payable		31,310			8,581
Accrued interest		11,815			12,216
Accrued salaries and benefits		3,309			2,948
Accrued taxes		265			212

		46,699			23,957


Commitments and Contingencies (Note 13)

Deferred Credits and Other Liabilities:
Accrued retirement benefits		3,808			11,691
Other		6,945			5,387

		10,753			17,078


TOTAL CAPITALIZATION AND LIABILITIES	$	3,579,200		$	3,213,877

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

164

SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED INCOME STATEMENTS
(Dollars in Thousands)


	Year ended December 31,
	2007			2006			2005
OPERATING EXPENSES:
Operation:
Other	$	3,599		$	5,952		$	19,006
Taxes:
Income taxes (benefits)		(15,650	)		(23,595	)		(33,078	)
Other than income		194			172			152

		(11,857	)		(17,471	)		(13,920	)

OPERATING INCOME		11,857			17,471			13,920

OTHER INCOME (EXPENSE):
Early debt conversion fees		—			—			(54,000	)
Subsidiary earnings		231,891			324,152			185,777
Other income		1,774			4,236			1,573
Other expense		(5,283	)		(6,595	)		(2,627	)
Income (taxes) / benefits		1,443			1,157			18,799

		229,825			322,950			149,522

Total Income Before Interest Charges		241,682			340,421			163,442

INTEREST CHARGES:
Long-term debt		42,481			51,431			74,323
Other		1,906			11,539			6,882

		44,387			62,970			81,205


Net Income Applicable to Common Stock	$	197,295		$	277,451		$	82,237


Amount per share basic and diluted
Net Income Applicable to Common Stock	$	0.89		$	1.33		$	0.44

Weighted Average Shares of Common Stock Outstanding — basic		222,180,440			208,531,134			185,548,314

Weighted Average Shares of Common Stock Outstanding — diluted		222,554,024			209,020,896			185,932,504

165

SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)


	Year ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash from Operating Activities	$	(20,193	)	$	(59,166	)	$	(147,993	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Investments in subsidiaries and other property — net		(134,383	)		(284,490	)		(231,182	)
Dividends received from subsidiaries		44,523			161,793			65,819

Net Cash used by Investing Activities		(89,860	)		(122,697	)		(165,363	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		—			—			21,677
Proceeds from issuance of long-term debt		—			—			220,211
Retirement of long-term debt		(25,373	)		(110,710	)		(132,949	)
Sale of Common Stock, net of issuance costs		213,339			281,554			235,618
Proceeds from exercise of stock option		548			1,040			590
Dividends paid		(35,417	)		—			—

Net Cash from Financing Activities		153,097			171,884			345,147


Net Increase (Decrease) in Cash and Cash Equivalents		43,044			(9,979	)		31,791
Beginning Balance in Cash and Cash Equivalents		25,206			35,185			3,394

Ending Balance in Cash and Cash Equivalents	$	68,250		$	25,206		$	35,185

166

Sierra Pacific Resources
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2007, 2006 and 2005
(Dollars in Thousands)


	Provision for
	Uncollectible Accounts
Balance at January 1, 2005	$	36,197
Provision charged to income		9,550
Amounts written off, less recoveries		(9,519)

Balance at December 31, 2005	$	36,228


Balance at January 1, 2006	$	36,228
Provision charged to income		13,476
Amounts written off, less recoveries		(10,138)

Balance at December 31, 2006	$	39,566


Balance at January 1, 2007	$	39,566
Provision charged to income		10,584
Amounts written off, less recoveries		(14,089)

Balance at December 31, 2007	$	36,061

Nevada Power Company
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2007, 2006 and 2005
(Dollars in Thousands)


	Provision for
	Uncollectible Accounts
Balance at January 1, 2005	$	30,901
Provision charged to income		6,966
Amounts written off, less recoveries		(7,481	)

Balance at December 31, 2005	$	30,386


Balance at January 1, 2006	$	30,386
Provision charged to income		10,795
Amounts written off, less recoveries		(8,347	)

Balance at December 31, 2006	$	32,834


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

167

Sierra Pacific Power Company
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2007, 2006 and 2005
(Dollars in Thousands)


	Provision for
	Uncollectible Accounts
Balance at January 1, 2004	$	5,296
Provision charged to income		2,584
Amounts written off, less recoveries		(2,038	)

Balance at December 31, 2004	$	5,842


Balance at January 1, 2006	$	5,842
Provision charged to income		2,681
Amounts written off, less recoveries		(1,791	)

Balance at December 31, 2006	$	6,732


Balance at January 1, 2007	$	6,732
Provision charged to income		1,315
Amounts written off, less recoveries		(2,378	)

Balance at December 31, 2007	$	5,669

168

2007 FORM 10-K EXHIBIT INDEX

(a) Exhibits Index

Certain of the following exhibits with respect to SPR and its subsidiaries, Nevada Power Company, Sierra Pacific Power Company, 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 Commission and are incorporated herein by reference.

(* filed herewith)

(3) Sierra Pacific Resources

	•		Restated and Amended Articles of Incorporation of Sierra Pacific Resources, dated May 24, 2006 (filed as Exhibit 3.1 to Form 10-Q for quarter ended June 30, 2006).

	•		By-laws of Sierra Pacific Resources as amended through May 3, 2005 (filed as Exhibit 3.1 to Form 8-K dated May 9, 2005).

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).

	•		Articles of Incorporation of Piñon Pine Corp., dated December 11, 1995 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1995).

	•		Articles of Incorporation of Piñon Pine Investment Co., dated December 11, 1995 (filed as Exhibit (3)(B) to Form 10-K for the year ended December 31, 1995).

	•		Agreement of Limited Liability Company of Piñon Pine Company, L.L.C., dated December 15, 1995, between Piñon Pine Corp., Piñon Pine Investment Co. and GPSF-B INC 1995 (filed as Exhibit (3)(C) to Form 10-K for the year ended December 31, 1995).

	•		Amended and Restated Limited Liability Company Agreement of SPPC Funding LLC dated as of April 9, 1999, in connection with the issuance of California rate reduction bonds (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1999).

(4) Sierra Pacific Resources

•

Indenture between 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).

	•		Officers’ Certificate dated August 12, 2005, establishing the terms of 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 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 Sierra Pacific Resources’ 7.803% Senior Notes due 2007 (filed as Exhibit 99.1 to Form 8-K dated June 16, 2005).

169

	•		Indenture, dated March 19, 2004, between 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 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).

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).

	•		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 9% General and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2003).

	•		Form of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2003).

	•		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).

170

•

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).

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).

	•		First Supplemental Indenture, dated as of May 1, 2001, establishing Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(b) 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).

	•		Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(c) to Form 10-Q for the quarter ended June 30, 2001).

	•		Form of Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(d) to Form 10-Q for the quarter ended June 30, 2001).

	•		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 General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(E) to Form 10-K for the year ended December 31, 2004).

	•		Form of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(F) to Form 10-K for the year ended December 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 Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Appendix A to Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006).

	•		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).

•

Indenture dated as of April 9, 1999 between SPPC Funding LLC and Bankers Trust Company of California, N.A., in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(C) to Form 10-K for the year ended December 31, 1999).

	•		First Series Supplement dated as of April 9, 1999 to Indenture between SPPC Funding LLC and Bankers Trust Company of California, N.A., in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999).

	•		Form of SPPC Funding LLC Notes, Series 1999-1, in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(E) to Form 10-K for year ended December 31, 1999).

(10) Sierra Pacific Resources

•

*(A) Employment letter dated May 21, 2002 for Donald L. Shalmy.

171

	•		*(B) Written description of employment arrangement for William D. Rogers.

	•		*(C) Written description of employment arrangement for Jeffrey L. Ceccarelli.

	•		*(D) Employment Letter dated May 9, 2007 for Michael W. Yackira.

	•		Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2003).

	•		Amendment to Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2006).

	•		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).

	•		Stephen R. Wood Employment Letter dated June 29, 2004 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004).

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

	•		Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Jeffrey L. Ceccarelli, Donald L. Shalmy, Michael W. Yackira, Roberto Denis, Stephen R. Wood and Paul J. Kaleta in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and Dennis D. Schiffel (filed as Exhibit 10(C) to Form 10-K for the year ended December 30, 2001).

	•		Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Mary O. Simmons and John E. Brown in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and John E. Brown (filed as Exhibit 10(D) to Form 10-K for the year ended December 30, 2001).

	•		Sierra Pacific Resources’ 2004 Executive Long-Term Incentive Plan (filed as Appendix A to 2004 Proxy Statement).

	•		Sierra Pacific Resources’ 2003 Non-Employee Director Stock Plan, as amended (filed as Exhibit 99.2 to Form S-8 dated October 19, 2007).

	•		Sierra Pacific Resources’ Employee Stock Purchase Plan (filed as Exhibit 99.3 to Form S-8 dated December 13, 1999).

Nevada Power Company

	•		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).

172

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company, dated August 1, 2006 (relating to Clark County, Nevada $39,500,000 Pollution Control Refund Revenue Bonds Series 2006) (filed as Exhibit 10.1 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 between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds Series 2006B) (filed as Exhibit 10.3 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).

	•		Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company, dated June 1, 2000 (Series 2000B) (filed as Exhibit 10(P) to Form 10-K for the year ended December 31, 2000).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company, dated November 1, 1997 (relating to Clark County, Nevada $52,285,000 Industrial Development Revenue Bonds, Series 1997A) (filed as Exhibit 10.83 to Form 10-K, File No. 1-4698, for the year ended December 31, 1997).

	•		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 1995B) (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).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1992 (Relating to Industrial Development Refunding Revenue Bonds, Series 1992C) (filed as Exhibit 10.67 to Form 10-K, File No. 1-4698, for the year ended December 31, 1992).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Relating to Clark County, Nevada $105,000,000 Industrial Development Revenue Bonds, Series 1992A) (filed as Exhibit 10.65 to Form 10-K, File No. 1-4698, for the year ended December 31, 1992).

	•		Collective Bargaining Agreement dated as of February 1, 2005, effective through February 1, 2008, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2005).

	•		Engineering, Procurement and Construction Agreement dated October 13, 2004 between Nevada Power Company and Fluor Enterprises, Inc. and Exhibit A thereto (filed as Exhibit 10.3 and Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004).

	•		Contract for Sale of Electrical Energy between the State of Nevada and Nevada Power Company, dated July 8, 1987 (filed as Exhibit 10.39 to Form 10-K, File No. 1-4698, for the year ended December 31, 1987).

173

	•		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).

	•		Amended Mohave Project Coal Supply Agreement dated May 26, 1976 between Nevada Power Company and Southern California Edison Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District and the Peabody Coal Company (filed as Exhibit 5.35 to Porto 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).

	•		Navajo Project Coal Supply Agreement dated June 1, 1970 between Nevada Power Company, the United States of America, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural District Tucson Gas & Electric Company and the Peabody Coal Company (filed as Exhibit 13.27B 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).

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).

	•		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).

174

	•		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).

	•		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).

	•		Financing Agreement dated as of March 1, 2001 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2001 (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2001).

	•		Transition Property Purchase and Sale Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 1999).

	•		Transition Property Servicing Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 1999).

	•		Administrative Services Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 1999).

	•		Collective Bargaining Agreement dated January 1, 2003, effective through December 31, 2005 between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local No. 1245 (filed as Exhibit 10(J) to Form 10-K for the year ended December 31, 2003).

	•		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).

	•		Coal Supply Agreement dated January 1, 2002 between Sierra Pacific Power Company and Arch Coal Sales Company, Inc. (5 year term ending on December 31, 2006) (filed as Exhibit 10(R) to Form 10-K for the year ended December 31, 2001).

	•		Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (confidential portions omitted and filed separately with the Securities and Exchange Commission) (filed as Exhibit 5-GG to Registration No. 2-62476).

	•		Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit(10)(B) to Form 10-K for the year ended December 31, 1991).

175

	•		Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal Stores Energy Company (filed as Exhibit (10)(A) to Form 10-K for the year ended December 31, 1993).

	•		Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(B) 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).

Sierra Pacific Communications

	•		Unit Redemption, Release, and Sale Agreement entered into by and among Touch America, Inc., Sierra Pacific Communications, and Sierra Touch America LLC, dated as of September 9, 2002 (filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2002).

	•		Amended and Restated Conduit Sale Agreement dated September 11, 2002, made by and between Sierra Pacific Communications and Quest Communications Corporation (filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2002).

(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 Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per share data have been omitted.

(12) Sierra Pacific Resources

•

*(A) Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company

•

*(B) Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company

•

*(C) Statement regarding computation of Ratios of Earnings to Fixed Charges.

(21) Sierra Pacific Resources

•

Nevada Power Company, a Nevada Corporation.
Sierra Pacific Power Company, 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.
Tuscarora Gas Pipeline Company, a Nevada Corporation.
Tuscarora Gas Operating Company, a Nevada Corporation.

176

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 Delaware Corporation.
SPPC Funding LLC, a Delaware Limited Liability Company.

(23) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

	•		*(A) Consent of Independent Registered Public Accounting Firm in connection with Sierra Pacific Resources’ 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.

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

	•		*(C) 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.

(31) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

	•		*(31.1) Annual Certification of Chief Executive Officer of Sierra Pacific Resources 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 Sierra Pacific Resources 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) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

	•		*(32.1) Certification of Chief Executive Officer of Sierra Pacific Resources 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 Sierra Pacific Resources 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.

177

Sierra Pacific Power 10-K/A2007 FY Annual report (amended)