e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 2006


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


	Registrant, Address of
Commission File	Principal Executive Offices and Telephone	I.R.S. employer	State of
Number	Number	Identification Number	Incorporation

1-08788	SIERRA PACIFIC RESOURCES	88-0198358	Nevada
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (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 89520-0400 (89511)
	(775) 834-4011

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

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

Sierra Pacific Resources:

Large accelerated filer

Accelerated filer

Non-accelerated filer

Nevada Power Company:

Large accelerated filer

Accelerated filer

Non-accelerated filer

Sierra Pacific Power Company:

Large accelerated filer

Accelerated filer

Non-accelerated filer

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

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


Class		Outstanding at August 2, 2006
Common Stock, $1.00 par value		200,921,764 Shares
of Sierra Pacific Resources

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 stated value, of Sierra Pacific Power Company.

This combined Quarterly Report on Form 10-Q 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.

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30,		December 31,
	2006		2005
ASSETS
Utility Plant at Original Cost:
Plant in service	$	7,701,627	$	6,801,916
Less accumulated provision for depreciation		2,259,008		2,169,316

		5,442,619		4,632,600
Construction work-in-progress		434,046		765,005

		5,876,665		5,397,605

Investments and other property, net		57,219		62,771


Current Assets:
Cash and cash equivalents		193,852		172,682
Restricted cash and investments		—		67,245
Accounts receivable less allowance for uncollectible accounts:
2006-$38,472; 2005-$36,021		450,960		413,171
Deferred energy costs — electric (Note 1)		165,126		253,697
Deferred energy costs — gas (Note 1)		208		5,825
Materials, supplies and fuel, at average cost		98,752		88,445
Risk management assets (Note 5)		34,733		50,226
Deferred income taxes		8,713		—
Deposits and prepayments for energy		31,805		45,054
Other		20,831		26,544

		1,004,980		1,122,889


Deferred Charges and Other Assets:
Goodwill (Note 8)		3,989		22,877
Deferred energy costs — electric (Note 1)		284,239		255,312
Deferred energy costs — gas (Note 1)		582		845
Regulatory tax asset		268,441		249,261
Other regulatory assets		623,217		568,145
Risk management assets (Note 5)		240		—
Risk management regulatory assets — net (Note 5)		64,661		—
Unamortized debt issuance costs		68,034		63,395
Other		119,556		107,330

		1,432,959		1,267,165

Assets of Discontinued Operations		20,028		20,116

TOTAL ASSETS	$	8,391,851	$	7,870,546

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	2,090,491	$	2,060,154
Preferred stock		—		50,000
Long-term debt		4,403,714		3,817,122

		6,494,205		5,927,276


Current Liabilities:
Current maturities of long-term debt		28,640		58,909
Accounts payable		265,357		252,900
Accrued interest		69,910		58,585
Dividends declared		74		1,043
Accrued salaries and benefits		27,698		32,186
Current income taxes payable		—		3,159
Deferred income taxes		—		129,041
Risk management liabilities (Note 5)		65,645		16,580
Accrued taxes		7,588		6,540
Contract termination liabilities		—		129,000
Other current liabilities		61,112		56,724

		526,024		744,667


Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes		622,541		451,924
Deferred investment tax credit		36,962		38,625
Regulatory tax liability		35,958		38,224
Customer advances for construction		186,251		170,061
Accrued retirement benefits		89,049		77,245
Risk management regulatory liability — net (Note 5)		—		15,605
Regulatory liabilities		280,178		284,438
Other		110,483		112,281

		1,361,422		1,188,403

Liabilities of Discontinued Operations		10,200		10,200

TOTAL CAPITALIZATION AND LIABILITIES	$	8,391,851	$	7,870,546

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
OPERATING REVENUES:
Electric	$	787,891		$	668,583		$	1,407,938		$	1,249,727
Gas		33,297			32,136			120,022			99,674
Other		731			319			1,015			611

		821,919			701,038			1,528,975			1,350,012


OPERATING EXPENSES:
Operation:
Purchased power		256,701			298,619			510,445			518,771
Fuel for power generation		214,168			107,838			357,277			217,840
Gas purchased for resale		24,352			23,024			91,748			76,504
Deferral of energy costs — electric — net		52,949			13,641			57,021			53,757
Deferral of energy costs — gas — net		1,353			1,332			6,084			1,004
Other		83,007			87,199			173,269			174,789
Maintenance		23,426			24,157			45,356			47,103
Depreciation and amortization		56,622			53,298			114,083			106,087
Taxes:
Income taxes / (benefits)		5,336			(1,683	)		(1,563	)		(9,513	)
Other than income		13,274			12,720			24,938			23,829

		731,188			620,145			1,378,658			1,210,171

OPERATING INCOME		90,731			80,893			150,317			139,841

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		4,174			4,889			10,306			8,698
Interest accrued on deferred energy		7,638			5,909			16,354			12,017
Carrying charge for Lenzie		9,135			—			13,166			—
Other income		9,334			9,204			18,597			19,343
Other expense		(4,716	)		(4,036	)		(9,434	)		(8,302	)
Income taxes		(8,758	)		(7,668	)		(16,943	)		(10,932	)

		16,807			8,298			32,046			20,824

Total Income Before Interest Charges		107,538			89,191			182,363			160,665

INTEREST CHARGES:
Long-term debt		77,279			78,579			150,662			157,006
Other		5,016			6,515			10,234			12,681
Allowance for borrowed funds used during construction		(4,007	)		(5,928	)		(10,009	)		(10,531	)

		78,288			79,166			150,887			159,156


INCOME FROM CONTINUING OPERATIONS		29,250			10,025			31,476			1,509

DISCONTINUED OPERATIONS:

Income (Loss) from discontinued operations (net of income taxes(benefits) of $36 $0, $31 and $(3) respectively)		(48	)		1			(57	)		6

NET INCOME		29,202			10,026			31,419			1,515
Preferred stock dividend requirements of subsidiary and premium on redemption		1,366			975			2,341			1,950

EARNINGS (DEFICIT) APPLICABLE TO COMMON STOCK	$	27,836		$	9,051		$	29,078		$	(435	)


Amount per share basic and diluted — (Note 7)
Income from continuing operations	$	0.15		$	0.05		$	0.16		$	0.01
Earnings applicable to common stock	$	0.14		$	0.05		$	0.14		$	—

Weighted Average Shares of Common Stock Outstanding — basic		200,897,101			183,338,153			200,882,857			117,569,589

Weighted Average Shares of Common Stock Outstanding — diluted		201,292,738			183,761,812			201,279,301			117,569,589

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

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	31,419		$	1,515
Non-cash items included in net income:
Depreciation and amortization		114,083			106,087
Deferred taxes and deferred investment tax credit		6,510			1,393
AFUDC and capitalized interest		(20,315	)		(19,229	)
Amortization of deferred energy costs — electric		75,025			90,831
Amortization of deferred energy costs — gas		4,136			(666	)
Other non-cash		(19,001	)		19,270
Changes in certain assets and liabilities:
Accounts receivable		(79,155	)		(50,759	)
Deferral of energy costs — electric		(34,151	)		(38,625	)
Deferral of energy costs — gas		1,744			1,427
Deferral of energy costs — terminated suppliers		2,309			—
Materials, supplies and fuel		(10,307	)		(7,068	)
Other current assets		18,961			12,736
Accounts payable		(4,022	)		44,008
Payment to terminating supplier		(65,368	)		—
Proceeds from claim on terminating supplier		41,365			—
Other current liabilities		12,358			4,990
Discontinued operations — operating activities		88			(9	)
Change in net assets of discontinued operations		—			1
Risk Management assets and liabilities		(15,948	)		(19,842	)
Other assets		5,804			210
Other liabilities		1,200			2,285

Net Cash from Operating Activities		66,735			148,555


CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(587,156	)		(364,642	)
AFUDC and other charges to utility plant		20,315			19,229
Customer advances for construction		16,190			13,992
Contributions in aid of construction		21,854			7,535

Net cash used for utility plant		(528,797	)		(323,886	)
Investments in subsidiaries and other property — net		11,127			3,452

Net Cash used by Investing Activities		(517,670	)		(320,434	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings		—			240,000
Change in restricted cash and investments		3,612			12,142
Net proceeds from issuance of long-term debt		2,043,333			50,000
Retirement of long-term debt		(1,522,793	)		(2,916	)
Redemption of preferred stock		(51,366	)		—
Sale of common stock, net of issuance cost		1,263			1,727
Dividends paid		(1,944	)		(1,965	)

Net Cash from Financing Activities		472,105			298,988


Net Increase in Cash and Cash Equivalents		21,170			127,109
Beginning Balance in Cash and Cash Equivalents		172,682			266,328

Ending Balance in Cash and Cash Equivalents	$	193,852		$	393,437


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	157,870		$	162,253
Income taxes	$	12		$	—

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands)

(Unaudited)


	June 30,			December 31,
	2006			2005
Common Shareholder’s Equity:
Common stock, $1.00 par value, authorized 350 million; issued and outstanding 2006: 200,920,000 shares; issued and outstanding 2005:200,792,000 shares	$	200,920		$	200,792

Other paid-in capital		2,222,027			2,220,896
Retained Deficit		(326,805	)		(355,883	)

Accumulated other comprehensive loss		(5,651	)		(5,651	)

Total Common Shareholder’s Equity		2,090,491			2,060,154

Preferred Stock of Subsidiaries:
Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value SPPC Class A Series 1; $1.95 dividend		—			50,000

Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% NPC Series Z due 2023		—			35,000
Debt Secured by First Mortgage Bonds
Revenue Bonds
Nevada Power Company
6.60% NPC Series 1992B due 2019		39,500			39,500
6.70% NPC Series 1992A due 2022		—			105,000
7.20% NPC Series 1992C due 2022		—			78,000
Sierra Pacific Power Company
6.35% SPPC Series 1992B due 2012		1,000			1,000
6.55% SPPC Series 1987 due 2013		39,500			39,500
6.30% SPPC Series 1987 due 2014		45,000			45,000
6.65% SPPC Series 1987 due 2017		92,500			92,500
6.55% SPPC Series 1990 due 2020		20,000			20,000
6.30% SPPC Series 1992A due 2022		10,250			10,250
5.90% SPPC Series 1993A due 2023		9,800			9,800
5.90% SPPC Series 1993B due 2023		30,000			30,000
6.70% SPPC Series 1992 due 2032		21,200			21,200
Medium Term Notes
Sierra Pacific Power Company
6.62% to 6.83% SPPC Series C due 2006		20,000			50,000
6.95% to 8.61% SPPC Series A due 2022		—			110,000
7.10% to 7.14% SPPC Series B due 2023		—			58,000

Subtotal		328,750			744,750

General and Refunding Mortgage Securities
Nevada Power Company
10.88% NPC Series E due 2009		12,554			162,500
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		227,500			227,500
5.875% NPC Series L due 2015		250,000			250,000
5.95% NPC Series M due 2016		210,000			—
6.65% NPC Series N due 2036		370,000			—
6.50% NPC Series O due 2018		325,000			—
Sierra Pacific Power Company
8.00% SPPC Series A due 2008		320,000			320,000
6.25% SPPC Series H due 2012		100,000			100,000
6.00% SPPC Series M due 2016		300,000			—

Subtotal		2,595,054			1,540,000

Debt Secured by General and Refunding Mortgage Securities
NPC Revolving Credit Facility		275,000			150,000
5.00% SPPC Series 2001 due 2036		80,000			80,000

Subtotal		355,000			230,000

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

(Continued)

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30,		December 31,
	2006		2005
ASSETS
Utility Plant at Original Cost:
Plant in service	$	4,970,802	$	4,106,489
Less accumulated provision for depreciation		1,193,638		1,128,209

		3,777,164		2,978,280
Construction work-in-progress		271,603		698,206

		4,048,767		3,676,486


Investments and other property, net		23,577		29,249


Current Assets:
Cash and cash equivalents		54,946		98,681
Restricted cash		—		52,374
Accounts receivable less allowance for uncollectible accounts:
2006-$31,934; 2005-$30,386		315,178		232,086
Accounts receivable, affiliated companies		13,790		3,738
Deferred energy costs — electric (Note 1)		122,359		186,355
Materials, supplies and fuel, at average cost		55,408		46,835
Risk management assets (Note 5)		21,010		22,404
Intercompany Income taxes receivable		39,317		—
Deposits and prepayments for energy		21,736		16,303
Other		13,361		16,075

		657,105		674,851


Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		239,633		214,587
Regulatory tax asset		154,734		155,304
Other regulatory assets		395,390		362,567
Risk management regulatory assets — net (Note 5)		39,190		—
Unamortized debt issuance costs		39,768		37,157
Other		41,932		23,720

		910,647		793,335

TOTAL ASSETS	$	5,640,096	$	5,173,921

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,755,605	$	1,762,089
Long-term debt		2,670,057		2,214,063

		4,425,662		3,976,152


Current Liabilities:
Current maturities of long-term debt		6,240		6,509
Accounts payable		186,058		164,169
Accrued interest		42,323		33,031
Dividends declared		74		397
Accrued salaries and benefits		12,610		15,537
Current income taxes payable		—		3,159
Deferred income taxes		3,811		57,392
Risk management liabilities (Note 5)		39,400		10,125
Accrued taxes		3,651		2,817
Contract termination liabilities		—		89,784
Other current liabilities		50,083		46,425

		344,250		429,345


Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		463,903		362,973
Deferred investment tax credit		16,022		16,832
Regulatory tax liability		14,417		15,068
Customer advances for construction		109,654		98,056
Accrued retirement benefits		28,655		24,614
Risk management regulatory liability — net (Note 5)		—		590
Regulatory liabilities		162,973		173,527
Other		74,560		76,764

		870,184		768,424


TOTAL CAPITALIZATION AND LIABILITIES	$	5,640,096	$	5,173,921

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

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2006			2005
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
Net Income	$	25,160		$	12,936
Non-cash items included in net income:
Depreciation and amortization		69,121			61,163
Deferred taxes and deferred investment tax credit		3,983			6,010
AFUDC		(16,226	)		(17,690	)
Amortization of deferred energy costs		52,399			72,135
Other non-cash		(25,816	)		17,670
Changes in certain assets and liabilities:
Accounts receivable		(119,536	)		(66,339	)
Deferral of energy costs		(31,516	)		(26,718	)
Deferral of energy costs — terminated suppliers		1,607			—
Materials, supplies and fuel		(8,573	)		(1,107	)
Other current assets		(2,718	)		(1,249	)
Accounts payable		9,011			41,758
Payment to terminating supplier		(37,410	)		—
Proceeds from claim on terminating supplier		26,391			—
Other current liabilities		10,858			7,113
Risk Management assets and liabilities		(9,111	)		(19,571	)
Other assets		4,700			210
Other liabilities		(3,102	)		(447	)

Net Cash from (used by) Operating Activities		(50,778	)		85,874


CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(439,465	)		(305,793	)
AFUDC and other charges to utility plant		16,226			17,690
Customer advances for construction		11,598			9,445
Contributions in aid of construction		15,402			295

Net cash used for utility plant		(396,239	)		(278,363	)
Investments in subsidiaries and other property — net		5,865			(917	)

Net Cash used by Investing Activities		(390,374	)		(279,280	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of long-term debt		1,549,833			50,000
Retirement of long-term debt		(1,120,448	)		(1,986	)
Dividends paid		(31,968	)		(25,259	)

Net Cash from Financing Activities		397,417			22,755


Net Decrease in Cash and Cash Equivalents		(43,735	)		(170,651	)
Beginning Balance in Cash and Cash Equivalents		98,681			243,323

Ending Balance in Cash and Cash Equivalents	$	54,946		$	72,672


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	92,705		$	85,213
Income taxes	$	3,159		$	—

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands)

(Unaudited)


	June 30,			December 31,
	2006			2005
Common Shareholder’s Equity:
Common stock, $1.00 par value, 1,000 shares authorized, issued and Outstanding	$	1		$	1
Other paid-in capital		1,808,848			1,808,848
Retained Deficit		(49,907	)		(43,422	)
Accumulated other comprehensive loss		(3,337	)		(3,338	)

Total Common Shareholder’s Equity		1,755,605			1,762,089

Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% Series Z due 2023		—			35,000
Debt Secured by First Mortgage Bonds
Revenue Bonds
6.60% Series 1992B due 2019		39,500			39,500
6.70% Series 1992A due 2022		—			105,000
7.20% Series 1992C due 2022		—			78,000

Subtotal		39,500			257,500

General and Refunding Mortgage Securities
10.88% Series E due 2009		12,554			162,500
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		227,500			227,500
5.875% Series L due 2015		250,000			250,000
5.95% Series M due 2016		210,000			—
6.65% Series N due 2036		370,000			—
6.50% Series O due 2018		325,000			—

Subtotal		1,875,054			1,120,000

Debt Secured by General and Refunding Mortgage Securities

Revolving Credit Facility		275,000			150,000

Unsecured Debt
Revenue Bonds
5.30% Series 1995D due 2011		14,000			14,000
5.35% Series 1995E due 2022		13,000			13,000
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
5.80% Series 1997B due 2032		20,000			20,000
5.90% Series 1997A due 2032		52,285			52,285
6.38% Series 1996 due 2036		20,000			20,000

Subtotal		331,335			331,335

Variable Rate Notes
PCRB Series 2000B due 2009		15,000			15,000
IDRB Series 2000A due 2020		100,000			100,000

Subtotal		115,000			115,000

Unamortized bond premium and discount, net		(13,409	)		(4,942	)

8.2% Junior Subordinated Debentures due 2037		—			122,548
7.75% Junior Subordinated Debentures due 2038		—			72,165

Subtotal		—			194,713

Obligations under capital leases		53,779			56,921
Current maturities and sinking fund requirements		(6,240	)		(6,509	)
Other, excluding current portion		38			45

Total Long-Term Debt		2,670,057			2,214,063

TOTAL CAPITALIZATION		4,425,662		$	3,976,152

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30,		December 31,
	2006		2005
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,730,825	$	2,695,427
Less accumulated provision for depreciation		1,065,370		1,041,107

		1,665,455		1,654,320
Construction work-in-progress		162,443		66,799

		1,827,898		1,721,119


Investments and other property, net		2,390		842


Current Assets:
Cash and cash equivalents		77,779		38,153
Restricted cash		—		14,871
Accounts receivable less allowance for uncollectible accounts:
2006-$6,538; 2005-$5,634		135,077		180,973
Accounts receivable, affiliated companies		—		40,278
Deferred energy costs — electric (Note 1)		42,767		67,342
Deferred energy costs — gas (Note 1)		208		5,825
Materials, supplies and fuel, at average cost		43,330		41,608
Risk management assets (Note 5)		13,723		27,822
Intercompany income taxes receivable		2,721		—
Deposits and prepayments for energy		10,069		28,751
Other		6,831		9,547

		332,505		455,170


Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		44,606		40,725
Deferred energy costs — gas (Note 1)		582		845
Regulatory tax asset		113,707		93,957
Other regulatory assets		227,827		205,578
Risk management assets (Note 5)		240		—
Risk management regulatory assets — net (Note 5)		25,471		—
Unamortized debt issuance costs		15,332		12,693
Other		13,225		15,372

		440,990		369,170

TOTAL ASSETS	$	2,603,783	$	2,546,301

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	750,611	$	727,777
Preferred stock		—		50,000
Long-term debt		1,072,566		941,804

		1,823,177		1,719,581


Current Liabilities:
Current maturities of long-term debt		22,400		52,400
Accounts payable		53,791		56,661
Accounts payable, affiliated companies		12,217		—
Accrued interest		13,152		10,993
Dividends declared		—		968
Accrued salaries and benefits		13,192		14,032
Current income taxes payable		—		49,673
Deferred income taxes		38,823		21,832
Risk management liabilities (Note 5)		26,245		6,455
Accrued taxes		3,841		3,541
Contract termination liabilities		—		39,216
Other current liabilities		11,029		10,299

		194,690		266,070


Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		264,018		244,244
Deferred investment tax credit		20,940		21,793
Regulatory tax liability		21,541		23,156
Customer advances for construction		76,597		72,005
Accrued retirement benefits		51,689		41,507
Risk management regulatory liability — net (Note 5)		—		15,015
Regulatory liabilities		117,205		110,911
Other		33,926		32,019

		585,916		560,650

TOTAL CAPITALIZATION AND LIABILITIES	$	2,603,783	$	2,546,301

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	22,271		$	17,036
Non-cash items included in net income:
Depreciation and amortization		44,962			44,924
Deferred taxes and deferred investment tax credit		(37,847	)		(11,456	)
AFUDC		(4,089	)		(1,539	)
Amortization of deferred energy costs — electric		22,626			18,696
Amortization of deferred energy costs — gas		4,136			(666	)
Other non-cash		6,230			3,511
Changes in certain assets and liabilities:
Accounts receivable		71,200			40,396
Deferral of energy costs — electric		(2,634	)		(11,907	)
Deferral of energy costs — gas		1,744			1,427
Deferral of energy costs — terminated suppliers		702			—
Materials, supplies and fuel		(1,722	)		(5,950	)
Other current assets		21,399			10,390
Accounts payable		5,746			4,158
Payment to terminating supplier		(27,958	)		—
Proceeds from claim on terminating supplier		14,974			—
Other current liabilities		2,348			(677	)
Risk Management assets and liabilities		(6,837	)		(271	)
Other assets		1,103			—
Other liabilities		8,220			516

Net Cash from Operating Activities		146,574			108,588


CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(147,691	)		(58,848	)
AFUDC and other charges to utility plant		4,089			1,539
Customer advances for construction		4,592			4,547
Contributions in aid of construction		6,452			7,240

Net cash used for utility plant		(132,558	)		(45,522	)
Disposal of (Investment in) subsidiaries and other property — net		(29	)		24

Net Cash used by Investing Activities		(132,587	)		(45,498	)


CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Change in restricted cash and investments		3,612			2,034
Net proceeds from issuance of long-term debt		493,500			—
Retirement of long-term debt		(402,181	)		(1,508	)
Redemption of preferred stock		(51,366	)		—
Dividends paid		(17,926	)		(1,954	)

Net Cash from (used by) Financing Activities		25,639			(1,428	)


Net Increase in Cash and Cash Equivalents		39,626			61,662
Beginning Balance in Cash and Cash Equivalents		38,153			19,319

Ending Balance in Cash and Cash Equivalents	$	77,779		$	80,981


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	38,541		$	36,444
Income taxes	$	12		$	—

Noncash Activities:
Transfer of Regulatory Asset (Note 8)	$	18,888		$	—

The accompanying notes are an integral part of the financial statements

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands)

(Unaudited)


	June 30,			December 31,
	2006			2005
Common Shareholder’s Equity:
Common stock, $3.75 par value, 1,000 shares authorized, issued and outstanding	$	4		$	4
Other paid-in capital		828,991			810,103
Retained Deficit		(76,591	)		(80,538	)
Accumulated other comprehensive loss		(1,793	)		(1,792	)

Total Common Shareholder’s Equity		750,611			727,777

Cumulative Preferred Stock:
Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value SPPC Class A Series 1; $1.95 dividend		—			50,000

Long-Term Debt:
Secured Debt
Debt Secured by First Mortgage Bonds
Revenue Bonds
6.35% Series 1992B due 2012		1,000			1,000
6.55% Series 1987 due 2013		39,500			39,500
6.30% Series 1987 due 2014		45,000			45,000
6.65% Series 1987 due 2017		92,500			92,500
6.55% Series 1990 due 2020		20,000			20,000
6.30% Series 1992A due 2022		10,250			10,250
5.90% Series 1993A due 2023		9,800			9,800
5.90% Series 1993B due 2023		30,000			30,000

6.70% Series 1992 due 2032		21,200			21,200
Medium Term Notes
6.62% to 6.83% Series C due 2006		20,000			50,000
6.95% to 8.61% Series A due 2022		—			110,000
7.10% to 7.14% Series B due 2023		—			58,000

Subtotal		289,250			487,250

General and Refunding Mortgage Securities
8.00% Series A due 2008		320,000			320,000
6.25% Series H due 2012		100,000			100,000
6.00% Series M due 2016		300,000			—

Subtotal		720,000			420,000

Debt Secured by General and Refunding Mortgage Securities
5.00% Series 2001 due 2036		80,000			80,000

Subtotal		80,000			80,000

Unsecured Debt
Unamortized bond premium and discount, net		(728	)		(666	)
Current maturities and sinking fund requirements		(22,400	)		(52,400	)
Other, excluding current portion		6,444			7,620

Total Long-Term Debt		1,072,566			941,804

TOTAL CAPITALIZATION	$	1,823,177		$	1,719,581

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements of Sierra Pacific Resources (SPR) include the accounts of SPR and its wholly-owned subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC) (collectively, the “Utilities”), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications (SPC) and Sierra Water Development Company (SWDC). SPC is a discontinued operation, and as such, is reported separately in the financial statements. The consolidated financial statements of NPC include the accounts of NPC and its wholly-owned subsidiary, Nevada Electric Investment Company (NEICO). The consolidated financial statements of SPPC include the accounts of SPPC and its wholly-owned subsidiaries, GPSF-B, Piñon Pine Corporation (PPC), Piñon Pine Investment Company, Piñon Pine Company, L.L.C. and Sierra Pacific Funding L.L.C. All significant intercompany transactions and balances 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.

In the opinion of the management of SPR, NPC, and SPPC, the accompanying unaudited interim consolidated financial statements contain all adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in SPR’s, NPC’s, and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2005 (the “2005 Form
10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the three and six months ended June 30, 2006, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

Certain items previously reported have been reclassified to conform to the current year’s presentation. Previously reported net income and shareholders’ equity were not affected by these reclassifications.

Deferral of Energy Costs

NPC and SPPC follow deferred energy accounting. See Note 1, Summary of Significant Accounting Policies, of Notes to Consolidated Financial Statements in NPC’s and SPPC’s 2005 Form 10-K, for additional information regarding the implementation of deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of June 30, 2006 (dollars in thousands):


	June 30, 2006
	NPC		SPPC			SPPC			SPR
Description	Electric		Electric			Gas			Total
Unamortized balances approved for collection in current rates

Electric – NPC Period 3 (effective 4/05, 2 years)	$	25,106	$	—		$	—		$	25,106
Electric – SPPC Period 3 (effective 6/05, 27 months)		—		15,047			—			15,047
Electric – NPC Period 4 (effective 4/05, 2 years)		44,007		—			—			44,007
Electric – SPPC Period 4 (effective 6/05, 1 year)		—		(3,142	)⁽¹⁾		—			(3,142	)
Electric – NPC Period 5 (effective 8/06, 2 years)		154,987		—			—			154,987
Electric – SPPC Period 5 (effective 7/06, 2 years)		—		41,180			—			41,180
Natural Gas – Period 5 (effective 11/05, 1 year)		—		—			443			443
LPG Gas – Period 3 (effective 11/04, 2 years)		—		—			4			4

Balances pending PUCN approval				—			2,575			2,575

Cumulative CPUC balance		—		9,095			—			9,095

Balances accrued since end of periods submitted for PUCN approval		55,507		4,784			(2,232	)⁽¹⁾		58,059

Claims for terminated supply contracts		82,385		20,409			—			102,794


Total	$	361,992	$	87,373		$	790		$	450,155


Current Assets

Deferred energy costs – electric	$	122,359	$	42,767		$	—		$	165,126
Deferred energy costs – gas		—		—			208			208

Deferred Assets

Deferred energy costs – electric		239,633		44,606			—			284,239
Deferred energy costs – gas		—		—			582			582

Total	$	361,992	$	87,373		$	790		$	450,155


(1)		Credits represent over-collections, that is, the extent to which gas or fuel and purchased power costs recovered through rates exceed actual gas or fuel and purchased power costs.

Carrying Charge on the Lenzie Generating Station

In 2004, the Public Utility Commission of Nevada (PUCN) granted NPC’s request to designate 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. Based on the regulatory order, through June 30, 2006, NPC has accumulated approximately $15.3 million in carrying charges; however, $2.1 million of this amount has not been recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through regulated rates. For financial reporting purposes, through June 30, 2006, NPC recognized $13.2 million in other income, and recorded a corresponding regulatory asset, which represents only the carrying charge component associated with incurred debt costs. NPC expects to seek recovery of the $15.3 million amounts in its next general rate case.

Recent Pronouncements

SFAS 123 (R)

SPR adopted Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), “Share Based Payment” (SFAS 123 R) in the first quarter of 2006 using the modified prospective method. The Company had previously applied the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”, in accounting for its stock compensation plans and in accordance with the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”, and the updated disclosure requirements set forth in SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure”. Accordingly, no compensation cost had been recognized previously.

SPR’s executive long-term incentive plan for key management employees permits the following types of grants, separately or in combination: non-qualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares and bonus stock. SPR currently issues Performance Shares and Non Qualified Stock Options (NQSO) under this plan. In addition, the Company also has an Employee Stock Purchase Plan (ESPP). Please refer to Note 13, Stock Compensation Plans in the Notes to Consolidated Financial Statements in the 2005 Form 10-K for additional information.

The adoption of SFAS 123 (R) did not have a material impact on the results of operations for SPR, NPC or SPPC.

SFAS 155

In February 2006, the Financial Accounting Standards Board (FASB) issued Statement No. 155 “Accounting for Certain Hybrid Financial Instruments (“SFAS 155”). This Statement amends FASB Statements No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS 155:

	•		permits fair value re-measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation;

	•		clarifies which interest-only strips and principal-only strips are not subject to the requirements of Statement 133,

	•		establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation;

	•		clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and

	•		amends Statement 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument.

This statement is effective for years beginning after September 15, 2006. Earlier adoption is permitted as of the beginning of an entity’s fiscal year, provided the entity has not yet issued financial statements, including financial statements for any interim period for that fiscal year. At adoption, any difference between the total carrying amount of the individual components of the existing bifurcated hybrid financial instrument and the fair value of the combined hybrid financial instrument should be recognized as a cumulative-effect adjustment to beginning retained earnings. SPR has early adopted SFAS 155, as of January 1, 2006, however, as of June 30, 2006, SPR and the Utilities do not have any financial instruments that meet the criteria specified under SFAS 155.

FIN 46(R)-6

In April 2006, the FASB issued FASB Staff Position (“FSP”) FIN 46R-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R). This FSP addresses certain implementation issues related to FASB Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities. Specifically, FSP FIN 46R-6 addresses how a reporting enterprise should determine the variability to be considered in applying FIN 46R. The variability that is considered in applying FIN 46R affects the determination of (a) whether an entity is a variable interest entity (“VIE”), (b) which interests are “variable interests” in the entity, and (c) which party, if any, is the primary beneficiary of the VIE. That variability affects any calculation of expected losses and expected residual returns, if such a calculation is necessary. SPR and the Utilities are required to apply the guidance in this FSP prospectively to all entities (including newly created entities) and to all entities previously required to be analyzed under FIN 46R when a “reconsideration event” has occurred, beginning July 1, 2006. SPR and the Utilities will evaluate the impact of this Staff Position at the time any such “reconsideration event” occurs, and for any new entities.

FIN 48

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109”, to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006. SPR and the Utilities are in the process of evaluating the impact of the adoption of this interpretation on SPR’s and the Utilities’ results of operations and financial condition.

NOTE 2. SEGMENT INFORMATION

SPR’s 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 to northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.

The net assets and operating results of SPC are reported as discontinued operations in the financial statements for 2006 and 2005. Accordingly, the segment information excludes financial information of SPC. NPC’s total assets increased from the amounts reported in the 2005 Form 10-K, mainly due to the acquisition of the Silverhawk Generation Facility in the first quarter of 2006 and construction costs associated with the Chuck Lenzie Facility. SPPC’s total assets increased from the amounts reported in the 2005 Form 10-K, mainly due to construction costs related to the Tracy Power Plant expansion and the transfer of $18.9 million of goodwill approved for recovery in rates for the gas business.

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 operating income. The accounting policies of the business segments are the same as those described in Note 1, Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in the 2005 Form 10-K. Inter-segment revenues are not material.

Financial data for business segments is as follows (dollars in thousands):


Three Months Ended	NPC		SPPC		Total						Reconciling
June 30, 2006	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	543,869	$	244,022	$	787,891	$	33,297	$	731	$	—	$	821,919


Operating Income	$	62,019	$	24,032	$	86,051	$	771	$	3,909	$	—	$	90,731


Three Months Ended	NPC		SPPC		Total						Reconciling
June 30, 2005	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	451,384	$	217,199	$	668,583	$	32,136	$	319	$	—	$	701,038


Operating Income	$	54,031	$	21,076	$	75,107	$	634	$	5,152	$	—	$	80,893


Six Months Ended	NPC		SPPC		Total						Reconciling
June 30, 2006	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	925,144	$	482,794	$	1,407,938	$	120,022	$	1,015	$	—	$	1,528,975


Operating Income	$	87,682	$	48,810	$	136,492	$	5,984	$	7,841	$	—	$	150,317


Assets	$	5,640,096	$	2,258,063	$	7,898,159	$	265,883	$	147,972	$	79,837	$	8,391,851


Six Months Ended	NPC		SPPC		Total						Reconciling
June 30, 2005	Electric		Electric		Electric		Gas		Other		Eliminations		Consolidated
Operating Revenues	$	805,518	$	444,209	$	1,249,727	$	99,674	$	611	$	—	$	1,350,012


Operating Income	$	77,296	$	44,939	$	122,235	$	6,290	$	11,316	$	—	$	139,841

NOTE 3. REGULATORY ACTIONS

Nevada Power Company

2006 Deferred Energy and BTER Update

On January 17, 2006, NPC filed a Deferred Energy Accounting Adjustment (DEAA) rate case application with the PUCN seeking recovery for purchased fuel and power costs and to increase its going forward Base Tariff Energy Rate (BTER) to reflect future energy costs. Refer to the 2005 Form 10-K for specific details about this filing.

On April 12, 2006, the PUCN approved an agreement among the interveners and NPC, which, effective May 1, 2006, set NPC’s BTER rates such that an estimated $112 million (revised by June 28, 2006 DEAA agreement – see below) of new revenues would be collected for fuel and power purchases in addition to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the $120 million increase represented an overall average rate increase of approximately 6.5%.

In the Deferred Energy portion of the case, NPC had requested authorization to recover $171.5 million of previously incurred purchased fuel and power costs during a one year period. On June 28, 2006, the PUCN approved a negotiated settlement, which specified (1) a reduction of $1.6 million to the BTER approved on April 12, 2006 based on an updated projection of costs and (2) granted NPC full recovery of the $171.5 million of deferred costs during a two year period beginning August 1, 2006; however the $171.5 million was reduced by a $16.5 million payment previously received by NPC in connection with the Lenzie acquisition. The agreement structured the cost recovery such that no rate increase was required. The DEAA rates required to recover the deferred balance are scheduled to occur during a two year period such that they will be offset by the expiration of previously approved DEAA rates.

Sierra Pacific Power Company

2006 Natural Gas Deferred Energy and BTER Update

On May 15, 2006, SPPC’s gas distribution operation filed an application with the PUCN seeking recovery of deferred natural gas costs accumulated between April 1, 2005 and March 31, 2006. The application sought to establish a new DEAA rate to recover $2.5 million of deferred natural gas costs and requested authorization to increase its going forward natural gas BTER to reflect forecasted gas costs. The new BTER is expected to increase revenue by $24.5 million. Combined with the expiration of a previous DEAA rate, which is expected to have fully collected its associated deferred balance before December 1, 2006, the requested rate increases total approximately 10%.

December 2005 Electric Deferred Energy and BTER Update

On December 1, 2005, SPPC filed an electric DEAA rate case application with the PUCN. The application sought recovery of purchased fuel and power costs and requested to increase its going forward BTER to reflect future energy costs. Refer to the 2005 Form 10-K for specific details about this filing.

On April 12, 2006, the PUCN issued an order authorizing SPPC to increase its BTER on May 1, 2006, such that SPPC expects to collect $31 million in new revenues for purchased power. The change represents a 3.5% increase to current customer rates.

In the Deferred Energy portion of this case, SPPC had requested authorization to begin a one year recovery of the $46.7 million of previously incurred purchased fuel and power costs on July 1, 2006. On June 7, 2006, the PUCN approved a negotiated settlement, which granted SPPC full recovery of the deferred costs during a two year period beginning July 1, 2006. The agreement structured the cost recovery such that no rate increase was required. The DEAA rates required to recover the $46.7 million deferred balance are scheduled to occur such that they will be offset by the expiration of previously approved DEAA rates.

2005 Electric and Gas General Rate Cases

On October 3, 2005, SPPC filed a gas general rate case along with its statutorily required electric general rate case. Refer to SPR’s 2005 Form 10-K for specific details about this filing.

On April 27, 2006, the PUCN issued its order to change electric and gas general rates. Although the order differed from the requested filing, the changes did not require material adjustments to net income for the six months ended June 30, 2006. The PUCN vote resulted in the following significant items:

•

Electric general revenue decrease: approximately $14 million annually or 1.5% effective May 1, 2006

	•		Gas general revenue increase: $4.5 million annually or 2.3%, effective May 1, 2006

	•		Electric Return on Equity and Rate of Return: 10.6% and 8.96% respectively

	•		Gas Return on Equity and Rate of Return: 10.6% and 7.98% respectively

	•		Approval to continue recovery of SPPC’s allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Electric customers

	•		Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Gas customers

	•		New depreciation rates for Gas and Electric facilities

	•		Deferred recovery of legal expenses related to the Enron purchased power contract litigation

NOTE 4. LONG-TERM DEBT

As of June 30, 2006, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the balance of 2006, for the next four years and thereafter are shown below (dollars in thousands):


							SPR Holding Co.		SPR
	NPC			SPPC			and Other Subs.		Consolidated
2006	$	7,906		$	21,044		$	—	$	28,950
2007		5,950			2,400			—		8,350
2008		7,066			322,400			—		329,466
2009		34,692			600			—		35,292
2010		282,843			—			—		282,843

		338,457			346,444			—		684,901
Thereafter		2,351,249			749,250			659,142		3,759,641

		2,689,706			1,095,694			659,142		4,444,542
Unamortized Premium(Discount) Amount		(13,409	)		(728	)		1,949		(12,188	)

Total	$	2,676,297		$	1,094,966		$	661,091	$	4,432,354

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

Financing Transactions (NPC)

General and Refunding Mortgage Notes, Series O

On May 12, 2006, NPC issued $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, and

	•		payment of related fees from the offering and for general corporate purposes

On June 26, 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 Notes. The aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018, outstanding is $325 million as of June 30, 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. The remaining proceeds were used to pay related fees and expenses from this offering, and for general corporate purposes.

General and Refunding Mortgage Notes, Series N

On April 3, 2006, NPC issued and sold $250 million of its 6.65% General and Refunding Mortgage Notes, Series N, due April 1, 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.

On June 26, 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 Notes. The aggregate principal amount of 6.65% General and Refunding Mortgage Notes, Series N, due 2036, outstanding is $370 million as of June 30, 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.

Tender Offer for General and Refunding Mortgage Notes, Series E

On June 1, 2006, NPC commenced a tender offer for all of its 10.875% General and Refunding Mortgage Notes, Series E, due 2009. In conjunction with that offer, NPC solicited the consent of holders of a majority in aggregate principal amount of the Notes to eliminate substantially all of the restrictive covenants contained in the officer’s certificate governing the Notes. Approximately $150 million of $162.5 million Series E notes outstanding were validly tendered and accepted by NPC. Those holders who tendered the Notes and delivered their consents by June 14, 2006 were entitled to receive a consent payment of $30 per $1000 principal amount of Notes, plus tender consideration for each $1,000 principal amount of Notes validly tendered. Those holders who tendered the Notes after June 14, 2006 but prior to June 28, 2006 were entitled to receive the tender consideration only. This tender consideration was $1,038.45 in cash plus accrued and unpaid interest up to the June 29, 2006 settlement date per $1,000 principal amount of the Notes tendered. Proceeds from the June 26, 2006 issuance of Series N and Series O Notes (discussed above) were used to fund the tender offer. The total consideration (including the consent payment and accrued interest) paid on June 29, 2006 was approximately $163.6 million. As of June 30, 2006, approximately $12.5 million of the Series E notes remain outstanding.

Revolving Credit Facility

On April 19, 2006, NPC increased the size of its second amended and restated revolving credit facility expiring 2010 to $600 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of June 30, 2006, NPC had $57 million of letters of credit outstanding and had borrowed $275 million under the revolving credit facility. As of July 28, 2006, NPC had $ 57.8 million of letters of credit outstanding and had borrowed $ 325 million 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 June 30, 2006, 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 9, Debt Covenant Restrictions in the Notes to Consolidated Financial Statements in the 2005 Form 10-K.

General and Refunding Mortgage Notes, Series M

On January 18, 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage Notes, Series M, due March 15, 2016. The Series M Notes were issued with registration rights. On February 10, 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 was borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Power Plant.

Financing Transactions (SPPC)

Revolving Credit Facility

under the revolving credit facility. As of July 28, 2006, SPPC had $10.3 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 June 30, 2006, 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 9, Debt Covenant Restrictions in the Notes to Consolidatd Financial Statements in the 2005 Form 10-K.

General and Refunding Mortgage Notes, Series M

On March 23, 2006, SPPC issued and sold $300 million of its 6.00% General and Refunding Mortgage Notes, Series M, due May 15, 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,

	•		payment 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,

	•		payment 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 $.4875 per share

The remaining $51 million of proceeds have been or will be used as follows:

	•		payment for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.62% to 6.65% Series C notes due November 2006; and

	•		payment of related fees and for general corporate purposes.

NOTE 5. DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC, and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. As amended, SFAS No. 133 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 qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. A majority of the contracts entered into by the Utilities meet the criteria specified for this exception.

SPR’s and the Utilities’ objective in using derivatives 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 forwards, options, and swaps. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

The following table shows the fair value of the derivatives recorded on the Consolidated Balance Sheets of SPR, NPC, and SPPC, and the related regulatory assets/liabilities. Due to deferred energy accounting 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 (dollars in millions):


	June 30, 2006						December 31, 2005
	SPR		NPC		SPPC		SPR			NPC			SPPC
Risk management assets	$	35.0	$	21.0	$	14.0	$	50.2		$	22.4		$	27.8
Risk management liabilities	$	65.6	$	39.4	$	26.2	$	16.6		$	10.1		$	6.5
Risk management regulatory assets (liabilities)	$	64.7	$	39.2	$	25.5	$	(15.6	)	$	(.6	)	$	(15.0	)

The decrease in net risk management assets as of June 30, 2006 as compared to December 31, 2005 is due to unfavorable positions on natural gas options which were purchased or sold to hedge energy price risk to customers.

Also included in risk management assets were $34.0 million, $20.8 million, and $13.2 million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at June 30, 2006.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Reid Gardner Station

In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, 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 10 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. Pond construction and lining costs expended to satisfy the NDEP order to date are approximately $29.4 million. Expenditures for 2006 through 2010 are projected to be approximately $21 million.

In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and on December 2, 2004 issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. On July 20, 2005, NDEP issued new Notices of Alleged Violations (NOAVs). In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. On July 26, 2005 NPC received a letter from the Environmental Protection Agency (EPA) requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has responded to the EPA information request. On June 20, 2006, the EPA issued a Finding and Notice of Violation (NOV).

NPC is engaged in an ongoing dialogue and settlement discussions with NDEP and the EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that may be required to achieve a settlement of the alleged violations. Management has booked an estimated minimum liability with respect to these matters. Any environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN for approval in NPC’s latest Integrated Resource Plan (IRP) filing.

Clark Station

In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark

Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. On October 31, 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time. On May 3, 2006, the EPA, by letter from the DOJ, notified NPC that it intends 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. NPC is continuing its discussions with the DOJ. NPC’s position is that a violation did not occur and is unable to predict the outcome of this action. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time.

NEICO

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

Sierra Pacific Power Company

PCB Treatment, Inc.

In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which has completed site investigations and along with the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. SPPC is a member of this steering committee. The EPA issued an administrative order on consent requiring the steering committee to oversee the performance of the work. One of the two buildings has been dismantled and the work has commenced on the other site. While the final cost to complete the work is not yet definite, SPPC’s share of the cost is not expected to be material.

Litigation

Nevada Power Company

Nevada Power Company 2001 Deferred Energy Case

On November 30, 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 spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.

On March 29, 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 affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.

Nevada Supreme Court rules mandate settlement talks before a matter is set for briefing and argument. As a result of that mandatory process, NPC filed a motion with the Nevada Supreme Court seeking remand of the matter back to the PUCN to consider new evidence uncovered after the PUCN’s final decision, but on November 2, 2004, the Nevada Supreme Court denied such motion for remand.

Oral argument was heard on February 23, 2006. On July 20, 2006, the Nevada Supreme Court ruled NPC is allowed to recover $180 million of the disallowed deferred energy costs and directed the District Court to remand the issue back to the PUCN to determine how the amount will be recovered in rates. In all other respects, the Nevada Supreme Court affirmed the District Court’s decision on the PUCN disallowance. Any party to the case may file a petition for rehearing with the Nevada Supreme Court within 18 days following the filing of the Court’s decision. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Peabody Western Coal Company

NPC owns an 11%, 255 MW interest in the Navajo Generating Station (Navajo) which includes three coal-fired electrical generating units and is located in Northern Arizona. Other participants in Navajo, are the Salt River Project (Salt River), Arizona Public Service Company, Los Angeles Department of Water and Power, and Tucson Electric Power Company (together the Joint Owners).

On October 15, 2004, coal supplier Peabody Western Coal Co. (Peabody) filed a complaint in Missouri State Court in St. Louis, seeking reimbursement of royalties and other costs and damages for alleged breach of the coal supply agreement for the Navajo plant. In January 2005, the Joint Owners were served and operating agent, Salt River, has engaged counsel and is defending the suit on behalf of the Joint Owners. NPC believes Peabody’s claims are without merit and intends to contest these.

On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a motion to remand the case back to state court in St. Louis, Missouri. Joint Owners have filed a motion to dismiss the complaint for lack of jurisdiction. On May 30, 2006, the Federal District Court granted Peabody’s motion and remanded the case back to state court. On June 29, 2006, Joint Owners filed a new motion to dismiss with the Missouri state court and requested a stay of the discovery proceedings pending the ruling on the new motion. Several discovery motions are pending. NPC is unable to predict the outcome of the decisions.

Sierra Pacific Power Company

Farad Dam

SPPC owns 4 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. A trial date has been set for November 14, 2006. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts or from other sources.

Management has not recorded a loss contingency for this matter, as the loss, if any, can not be estimated at this time.

Piñon Pine

In its 2003 General Rate Case, 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 General Rate Case 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. On July 20, 2006, the Supreme Court issued an order questioning the finality of the District Court’s decision and thus whether it has jurisdiction over the appeal and invited the parties to brief this matter.

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.

Regulatory Contingencies

Nevada Power Company

Mohave Generation Station (Mohave)

NPC’s ownership interest in Mohave comprises approximately 10% of NPC’s peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave and NPC owns approximately 14% of the facility.

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 the Mohave Generation Station (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 1, 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.

On December 31, 2005 the Owners of the Mohave plant suspended operation, pending resolution of these issues. However, on June 19, 2006, 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. The co-tenancy agreement and the operating agreement between the Owners expired on July 1, 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 2003 General Rate Case, the PUCN ordered the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its shutdown with recovery of any accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave in rates, as such, associated savings are currently recorded as a reduction in electric operating revenues - other. Approximately $27.2 million was reclassified from Plant in Service to Other Regulatory assets on December 31, 2005. NPC continues to accumulate all costs and savings associated with the shut down of Mohave in Other Regulatory Assets which has a balance of $17.9 million as of June 30, 2006. In its next general rate case, NPC will seek further clarification on the regulatory treatment of Mohave. In the event any portion of Mohave is disallowed, NPC will have to evaluate the asset for impairment.

NOTE 7. 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. Due to a net deficit for the six months ended June 30, 2005 these items are anti-dilutive. Accordingly, diluted EPS for that period are computed using the weighted average shares outstanding before dilution.

For the three and six months ended June 30, 2005, SPR had outstanding $300 million in 7.25% convertible notes due 2010 that were entitled to receive (non-cumulative) dividend payments on a 1:1 basis for dividends paid to common shareholders without exercising the conversion option. These convertible notes met the criteria of a participating security in the calculation of basic EPS, and were convertible at the option of the holders into 65,749,110 common shares. See Note 7, Long-Term Debt in the Notes to Consolidated Financial Statements in the 2005 Form 10-K, for discussion of the Convertible Notes.

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. However, due to a net deficit for the six months ended June 30, 2005, the effect of the participating securities are anti-dilutive, and as such, they have not been included in basic or diluted earnings per share. 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 following table outlines the calculation for earnings per share (EPS):


	Three months ended					Six Months ended
	June 30,					June 30,
	2006			2005		2006			2005
Basic EPS
Numerator ($000)
Income from continuing operations	$	29,250		$	10,025	$	31,476		$	1,509
Income/(Loss) from discontinued operations	$	(48	)	$	1	$	(57	)	$	6

Earnings/(Deficit) applicable to common stock	$	27,836		$	5,805	$	29,078		$	(435	)
Earnings applicable to convertible notes	$	—		$	3,246	$	—		$	—

Earnings/(Deficit) used for basic calculation	$	27,836		$	9,051	$	29,078		$	(435	)


Denominator
Weighted average number of common shares outstanding		200,897,101			117,589,043		200,882,857			117,569,589
Shares from conversion of notes		—			65,749,110		—			—

		200,897,101			183,338,153		200,882,857			117,569,589


Per Share Amounts
Income from continuing operations	$	0.15		$	0.05	$	0.16		$	0.01
Income/(Loss) from discontinued operations	$	—		$	—	$	—		$	—

Earnings/(Deficit) applicable to common stock	$	0.14		$	0.05	$	0.14		$	—

Diluted EPS
Numerator ($000)
Income from continuing operations	$	29,250		$	10,025	$	31,476		$	1,509
Income/(Loss) from discontinued operations	$	(48	)	$	1	$	(57	)	$	6

Earnings/(Deficit) applicable to common stock	$	27,836		$	9,051	$	29,078		$	(435	)

Denominator₍₁₎

Weighted average number of shares outstanding before dilution		200,897,101			117,589,043		200,882,857			117,569,589
Stock options		76,273			39,455		75,089			—
Executive long term incentive plan — restricted		105,060			232,173		108,567			—
Non-Employee Director stock plan		28,531			32,872		26,909			—
Employee stock purchase plan		2,347			5,781		2,454			—
Performance Shares		183,426			113,378		183,426			—
Convertible Stock		—			65,749,110		—			—

		201,292,738			183,761,812		201,279,301			117,569,589


Earnings (Deficit) Per Share Amounts
Income from continuing operations	$	0.15		$	0.05	$	0.16		$	0.01
Income/(Loss) from discontinued operations	$	—		$	—	$	—		$	—

Earnings/(Deficit) applicable to common stock	$	0.14		$	0.05	$	0.14		$	—


(1)		The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the three and six months ended June 30, 2006 and 2005, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the three and six months ended June 30, 2006, 942,908 and 933,433 shares, respectively, would be included and 397,655 and 768,509 shares, respectively, would be included for the three and six months ended June 30, 2005. The denominator does not include stock equivalents resulting from the conversion of the Corporate PIES, for the three and six months ended June 30, 2005. The amounts that would be included in the calculation, if the conversion price were met would be 17.3 million shares for each period.

NOTE 8. GOODWILL AND OTHER MERGER COSTS

On April 27, 2006, the PUCN issued a decision on SPPC’s general rate case for the gas distribution business that included the recovery of goodwill and other merger costs allocated to SPPC resulting from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that SPPC demonstrated merger savings exceeded merger costs, the requisite requirement for recovery of goodwill and merger costs. As a result of the PUCN decision, goodwill of approximately $18.9 million was reclassified as a regulatory asset and transferred from the financial statements of SPR to the financial statements of

SPPC as of June 30, 2006. See Note 3 of the Condensed Notes to Consolidated Financial Statements, Regulatory Actions for more information regarding the SPPC general rate decision.

The approximately $4 million of goodwill assigned to SPR’s unregulated operations were subject to impairment review under the provisions of SFAS No. 142, “Accounting for Goodwill, Other Intangible Assets.” SFAS No. 142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was developed for SPR’s unregulated businesses (TGPC and LOS) to determine the fair value of each reporting unit as of March 31, 2006. As a result, goodwill assigned to TGPC and LOS was determined not to be impaired.

The change in the carrying amount of goodwill for the six-month period ended June 30, 2006 and the allocation of the remaining balance is as follows (dollars in thousands):


	Regulated			Unregulated
	Operations			Operations		Total
Balance as of December 31, 2005	$	18,888		$	3,989	$	22,877

Transfer to SPPC regulatory asset as of June 30, 2006		(18,888	)


Balance as of June 30, 2006	$	—		$	3,989	$	3,989


Goodwill Allocation to Reporting Units:

TGPC	$	—		$	3,520	$	3,520
LOS		—			469		469


Balance as of June 30, 2006	$	—		$	3,989	$	3,989

NOTE 9. PENSION AND OTHER POST-RETIREMENT BENEFITS

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


	Pension Benefits						Other Postretirement Benefits
	2006			2005			2006			2005

Service cost	$	11,517		$	9,241		$	1,767		$	1,641
Interest cost		18,313			16,124			5,142			4,929
Expected return on plan assets		(20,365	)		(18,083	)		(2,460	)		(1,931	)
Amortization of prior service cost		946			857			61			32
Amortization of Transition Obligation		—			—			485			485
Amortization of net (gain)/loss		4,889			3,227			2,307			1,891
Special Termination Charges		—			362			—			6

Net periodic benefit cost	$	15,300		$	11,728		$	7,302		$	7,053

Management is re-assessing the amounts to be funded for each of the plans in 2006. The amounts previously disclosed in Note 12, Retirement Plan and Post-retirement Benefits, in the Notes to Consolidated Financial Statements in the 2005 Form 10-K, were $15 million for the pension plan and $14.7 million for other postretirement benefits.

NOTE 10. DEBT COVENANT RESTRICTION

Dividends Restrictions Applicable to the Utilities

regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In the PUCN order for Dockets 05-10024 and 05-10025, dated February 28, 2006, a dividend restriction was instituted for both utilities. Under this restriction, the combined amount that NPC and SPPC may pay to SPR each year is limited to the amount of SPR’s annual debt service. This restriction will expire when the Utilities’ senior secured debt is rated investment grade by two of the three credit rating agencies.

In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific agreements entered into by the Utilities, restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are discussed in detail in the 2005 Form 10-K, Note 9, Debt Covenant Restrictions of the Notes to Consolidated Financial Statements. In connection with NPC’s tender offer for its 10.875% General and Refunding Mortgage Notes, Series E in June 2006, substantially all of the restrictive covenants under the Series E Notes have been eliminated, including the dividend restriction contained in the Series E Notes. See Note 4, Long-Term Debt, in the Notes to Financial Statements for details of the Series E Notes tender offer. When SPPC redeemed all of its outstanding Class A, Series 1 Preferred Stock (See Note 11, Preferred Stock, below), it effectively eliminated the enforceability of the dividend restriction contained in its articles of incorporation because all of SPPC’S remaining stock is held by SPR.

As of June 30, 2006, each Utility was able to pay dividends, subject to a cap, under the most restrictive test in its financing agreements; however, the total amount of dividends that the Utilities can pay to SPR under their financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under their respective financing agreements is greater than the amount that the Utilities can pay under the PUCN dividend restrictions.

NOTE 11. PREFERRED STOCK

Sierra Pacific Power Company

Preferred Stock

On June 1, 2006, SPPC redeemed $50 million of its Class A, Series l Preferred Stock. Two million shares of stock were redeemed at a redemption price per share of $25.683, plus accrued dividends at the redemption date of $0.4875 per share.

NOTE 12. COMMON STOCK AND OTHER PAID-IN CAPITAL

Increased Authorized Shares

On May 1, 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.


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

Forward-Looking Statements and Risk Factors

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

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

	(1)		unseasonable weather and other natural phenomena, which, in addition to affecting the Utilities’ customers’ demand for power, can have a potentially serious impact on the Utilities’ ability to procure adequate supplies of fuel or purchased power to serve their respective customers and on the cost of procuring such supplies;

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

	(3)		whether NPC will be successful in obtaining Public Utility Commission of Nevada (PUCN) approval to recover the outstanding balance of its other regulatory assets and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

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

	(5)		the ability of SPR, NPC and SPPC to maintain access to the capital markets to support their requirements for working capital, including amounts necessary to finance deferred energy costs, as well as for construction and acquisition costs and other capital expenditures, particularly in the event of unfavorable rulings by the PUCN, a downgrade of the current debt ratings of SPR, NPC, or SPPC and/or adverse developments with respect to the Utilities’ power and fuel suppliers;

	(6)		whether the Utilities will be able to continue to pay SPR dividends under the terms of their respective financing and credit agreements, their regulatory order from the PUCN, and limitations imposed by the Federal Power Act;

	(7)		wholesale market conditions, including availability of power on the spot market, which affect the prices NPC and SPPC (the Utilities) have to pay for power as well as the prices at which the Utilities can sell any excess power;

	(8)		the final outcome of SPPC’s pending lawsuit in Nevada state court seeking to reverse the PUCN’s 2004 decision on SPPC’s 2003 General Rate case disallowing the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project;

	(9)		the effect that any future terrorist attacks, wars, threats of war, or epidemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the economy in general;

	(10)		industrial, commercial, and residential growth in the service territories of the Utilities;

	(11)		the financial decline of any significant customers;

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

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

	(14)	changes in environmental laws or regulations, including the imposition of significant new limits on emissions from electric generating facilities, such as requirements to reduce carbon dioxide (CO2) emissions in response to climate change legislation;

	(15)	the effect that any construction defects or accidents may have on our business, such as the risk of equipment failure, work accidents, fire or explosions, each of which may result in personal injury or loss of life, business interruptions, delay of in-service dates, property and equipment damage, pollution and environmental damage;

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

	(17)	future economic conditions, including inflation rates and monetary policy;

	(18)	financial market conditions, including changes in availability of capital or interest rate fluctuations;

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

	(20)	employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages.

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

EXECUTIVE OVERVIEW

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

	o		Results of Operations

	o		Analysis of Cash Flows

	o		Liquidity and Capital Resources

	o		Regulatory Proceedings (Utilities)

	o		Recent Pronouncements

SPR’s Utilities operate three regulated business segments: NPC electric, SPPC electric and SPPC natural gas service. Both Utilities provide electric service, and SPPC provides natural gas service. Other segment operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of SPR and account for substantially all of SPR’s assets and revenues. SPR, NPC and SPPC are separate filers for SEC reporting purposes and accordingly, this discussion has been divided to reflect the individual filers (SPR, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

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

NPC’s revenues for the six months ended June 30, 2006 increased from the same period in 2005 primarily as a result of higher rates and to a lesser extent customer growth. Electric rates increased as a result of various deferred energy cases and BTER updates as discussed in the 2005 Form 10-K and later under Regulatory Proceedings. NPC’s net income for the six months ended June 30, 2006 increased primarily as a result of increased revenues, the carrying charge associated with the Lenzie generating station and interest accrued on deferred energy.

SPPC electric and gas revenues increased primarily as a result of higher rates and to a lesser extent customer growth. Electric and gas rates increased as a result of various deferred energy cases and BTER updates as discussed in the 2005 Form 10-K and later under Regulatory Proceedings.

SPR recognized net income of $31.4 million for the six months ended June 30, 2006, compared to net income of $1.5 million for the same period in 2005. Net income increased primarily due to an increase in operating income, a decrease in interest charges due to refinancing activities, increased interest on deferred energy and the carrying charge associated with the Lenzie generating station.

Business Issues

SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core business. In order to concentrate more fully on its rapidly growing utility businesses, on July 10, 2006, SPR announced its decision to explore the potential opportunities for the sale of its 50 percent interest in the Tuscarora Gas Transmission Company.

SPR’s and the Utilities’ strategies are aimed at owning more generating facilities, reducing dependence on purchased power and diversifying fuel mix while the Utilities’ service areas continue to grow. The Utilities will continue to be subject to fluctuations in the volatile energy markets to the extent that the requirements of their customers are in excess of the Utilities’ owned generation, as well as the natural gas markets for SPPC.

Growth in Nevada shows no signs of slowing. New customer hookups remain near record levels. In addition, there are many large hotel/casino developments under construction in the vicinity of the Las Vegas Strip (i.e. Project City Center, Echelon, etc).

With the significant amounts of construction costs in the Utilities’ future, SPR and the Utilities will need to raise substantial amounts of capital to fund the expenditures. As a result, reducing the cost of capital by attaining investment grade ratings for the Utilities’ secured debt is a significant business focus in 2006. The Utilities continue to make progress toward this goal as indicated by a positive outlook from Fitch and improved credit ratios.

Generation Strategy

In 2003, NPC and SPPC embarked on a strategy to build or acquire electric power plants in order to reduce their exposure to the energy markets, thereby reducing prices and volatility for its customers, and to provide an opportunity for increased earnings. In line with

this strategy, in October 2004, upon PUCN approval, NPC purchased a partially constructed nominally rated 1,200 MW natural gas-fired high efficiency combined cycle power plant from Duke Energy (“Lenzie”).

The PUCN granted NPC’s request that Lenzie be designated a critical facility and allowed a 2% enhancement above NPC’s authorized Return on Equity (ROE) to be applied to the rate base associated with the Lenzie construction costs expended after acquisition. The order allows for up to an additional 1%, or a total of 3% enhanced ROE if the two Lenzie generator units were brought on line on or before dates specified in the order. In January 2006, NPC declared Block 1 of Lenzie commercially operable and in April 2006 declared Block 2 commercially operable, both ahead of the dates specified by the PUCN to qualify for the additional enhancement.

In January 2006, NPC completed the $208 million purchase of a 75 percent ownership interest in the Silverhawk Power Plant (“Silverhawk”) from Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy Corporation (PWEC), a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC (“GenWest”). Silverhawk is a 560-megawatt, natural gas-fueled high efficiency combined-cycle electric generating facility located 20 miles northeast of Las Vegas.

With the completion of Lenzie and an 80 MW combustion turbine at NPC’s Harry Allen site, plus the acquisition of Silverhawk, NPC more than doubled its owned capacity since the beginning of this year. As a result, NPC is less dependent upon the wholesale power markets for meeting the energy needs of its customers and expects to produce approximately 63% of its energy needs from owned generation, up from about 39% last year.

On December 14, 2005, the PUCN issued an order granting approval for SPPC to construct a 514 MW gas fired high efficiency combined cycle generator at the Tracy Plant. The PUCN also allowed SPPC to include construction work in progress balances in the rate base of any interim general rate cases and granted a 1.5% enhanced ROE for the estimated $421 million investment. In January 2006, SPPC signed contracts for construction of the unit and construction has begun. SPPC anticipates an in service date of June 2008. The unit will provide needed generation within SPPC’s control area to reliably serve the growing needs of Northern Nevada.

Recently filed integrated resource plans (IRP), filed by the Utilities, requests PUCN approval to develop a major energy project located near Ely, Nevada (the “Ely Energy Center”). The project includes two 750 MW coal-fired units utilizing the latest, state-of-the-art, fully-environmental compliant, clean pulverized coal technologies, and the construction of a 250-mile transmission line to interconnect NPC and SPPC. Subject to regulatory approvals and permitting requirements, it is anticipated the first coal plant would be operational in 2011 with the second unit in 2013. The total estimated capital expenditures associated with the two coal plants and the transmission line is approximately $3.7 billion. The IRP also requests approval to construct 600 MW of gas fired combustion turbines. The Utilities have also embarked on a strategy to invest in renewable energy that, along with contracts from third parties, will provide the opportunity for the Utilities to meet the Portfolio Standard as set forth by Nevada statute. See Regulatory Proceedings later for further details of the IRP.

Management of Energy Risk

The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. While NPC has greatly reduced its dependence on wholesale power markets to meet its customers’ demand, both Utilities continue to have a significant need to tap energy markets due to the fact that the Utilities’ ownership is insufficient to meet their customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk — the prospect that energy supplies will not be sufficient to fulfill customer requirements.

The Utilities systematically manage and control each of the energy-related risks through three primary vehicles – organization and governance, energy risk management programs, and energy risk control practices.

The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.

The Utilities follow PUCN-approved energy supply plans that encompass the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for economic hedging in conjunction with energy purchases and sales are also used to mitigate these risks.

Liquidity and Access to Capital Markets

With rising energy costs and substantial commitments to construction, SPR and the Utilities’ liquidity needs and access to capital markets is a significant business issue. As such, management continues to evaluate opportunities to refinance high yield debt at lower interest rates. Management is focused on returning the Utilities’ senior secured debt to investment grade credit quality. Significant amounts of capital may be necessary to fund the construction costs of new power plants and, as such, management may be required to meet such financial obligation with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and, if necessary, capital contributions from SPR. If energy costs rise at a rapid rate, and the Utilities do not recover, in a timely manner, the cost of fuel and purchased power, the Utilities may need to issue more debt to support their operating costs.

So far in 2006, the Utilities completed major financing transactions that lowered our interest costs, improved liquidity and extended maturities which include:

	•		issuance of $325 million of NPC’s 6.5% General and Refunding Mortgage Notes, Series O, due 2018

	•		issuance of $370 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036

	•		issuance of $210 million of NPC’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016

	•		increases to both NPC and SPPC Revolving Credit facility to $600 million and $350 million, respectively

	•		issuance of $300 million of SPPC’s 6.0% General and Refunding Mortgage Notes, Series M, due 2016

	•		redemptions of various NPC debt of approximately $563 million

	•		redemption and payments of various SPPC debt of approximately $248 million

Regulatory

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for annual rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every two years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. In addition, as necessary the Utilities can file for a change to their BTER rates to more closely match actual prices. The Utilities remain committed to maintaining a positive relationship with their regulators. Details regarding recently approved and pending rate cases are discussed below in Regulatory Proceedings and in the 2005 Form 10-K.

SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Consolidated)

The operating results of SPR primarily reflect those of NPC and SPPC, discussed later. The Holding Company’s (stand alone) operating results included approximately $25.9 million and $39.2 million of interest costs for the six months ended June 30, 2006 and 2005, respectively. The decrease in interest costs were primarily due to the conversion of SPR’s $300 million 7.25% Convertible Notes due 2010 and the Settlement of the Premium Income Equity Securities (PIES). See Note 7, Long-Term Debt in the Notes to Consolidated Financial Statements in the 2005 Form 10-K.

During the three months ended June 30, 2006, SPR had earnings applicable to common stock of approximately $27.8 million compared to $9.1 million for the same period in 2005. The change in SPR’s consolidated results for the three months ended June 30, 2006 compared to the same period in 2005 was primarily due to an increase in operating income, as discussed further in NPC and SPPC’s sections, the carrying charge on the Lenzie generating facility and increased interest on deferred energy. These increases were partially offset by the premium paid to redeem SPPC preferred stock.

During the six months ended June 30, 2006 SPR had earnings applicable to common stock of approximately $29.1 million compared to an approximate $435 thousand deficit applicable to common stock for the same period in 2005. Earnings increased primarily due to the items noted above for the three months ended June 30, 2006 and a decrease in interest expense compared to the same period in the prior year.

ANALYSIS OF CASH FLOWS

SPR’s consolidated net cash flows decreased for the six months ended June 30, 2006 compared to the same period in 2005, primarily as a result of an increase to plant in service and a decrease in cash from operations, offset partially by an increase in cash from financing activities.

At various times within the first six months in 2006, NPC borrowed approximately $660 million under its revolving credit facility of which approximately $535 million was repaid from the proceeds of issuance of $905 million of NPC’s General Refunding Mortgage Notes, Series M, N and O. The remainder of the proceeds, together with the draw on the credit facility, was utilized to redeem approximately $563 million of outstanding debt and to pay associated costs, to finance net

construction costs of $390 million and for operating activities. During this period SPPC borrowed approximately $198 million under its revolving credit facility which was utilized to retire $198 million of SPPC’s Medium Term Series A, B and C Notes and associated costs. SPPC also issued $300 million 6.0% General and Refunding Mortgage Notes Series M, the proceeds of which were used to pay off the amount owed under the revolving credit facility and to redeem $50 million of preferred stock and associated costs, premium and dividends. The balance will be used to redeem $20 million in maturing debt.

Cash used by investing activities increased significantly when compared to the same period in 2005 due primarily to the acquisition of the Silverhawk facility by NPC and for SPPC’s expansion of the Tracy Generating Station. This was offset by a reduction in construction at the Lenzie Generating Station which was placed in service in 2006.

Cash from operations decreased during the six months ended June 30, 2006, when compared to the same period in 2005, due primarily to increases in accounts receivable due to unseasonably warm weather, a decrease in collections for deferred energy balances due to the ending of collection periods, and the settlement with Enron during the first quarter. In addition, NPC’s payments in 2006 for obligations existing at December 31, 2005 to power suppliers were not offset by similar obligations at June 30, 2006 due to new generation capacity. In contrast, the payments made in 2005 for obligations existing at December 31, 2004 were offset by new and increased obligations at June 30, 2005 for the start of the summer peak.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Overall Liquidity

SPR’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and interest. SPR, on a stand-alone basis, had cash and cash equivalents of approximately $59.6 million at June 30, 2006.

SPR has approximately $51.8 million payable of debt service obligations for 2006 of which SPR paid approximately $25.9 million, through dividends from the Utilities during the six months ended June 30, 2006. SPR has approximately $25.9 million payable of debt service obligations remaining during 2006, which SPR expects to meet through the payment of dividends by the Utilities to SPR. See Dividends from Subsidiaries below.

SPR and the Utilities anticipate that they will be able to meet operating costs such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy and external borrowings. However, to fund capital requirements, as discussed in the 2005 Form 10-K, SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities and if necessary, the issuance of long term debt and/or capital contributions from SPR.

During the three months ended June 30, 2006, there were no material changes to contractual obligations as set forth in SPR’s 2005 Form 10-K for SPR (holding company). However, NPC and SPPC did enter into certain contractual obligations, which are discussed in their respective sections.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of June 30, 2006, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $99 million of its unsecured 7.803% Senior Notes due 2012; $225 million of its 6.75% Senior Notes due 2017; and $335 million of its unsecured 8.625% Senior Notes due 2014.

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

As of June 30, 2006, SPR, NPC, SPPC, and their subsidiaries had approximately $4.4 billion of debt and other obligations outstanding, consisting of approximately $2.67 billion of debt at NPC, approximately $1.07 billion of debt at SPPC and approximately $0.66 billion of debt at the holding company and other subsidiaries. Although SPR and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, SPR and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

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. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In the PUCN order for Dockets 05-10024 and 05-10025, dated February 28, 2006, a dividend restriction was instituted for both utilities. Under this restriction, the combined amount that NPC and SPPC may pay to SPR each year is limited to the actual cash necessary to service SPR’s debt for the year. This restriction will expire when the Utilities’ senior secured debt is rated investment grade by two of the three credit rating agencies.

As of June 30, 2006, each Utility was able to pay dividends, subject to a cap, under the most restrictive test in its financing agreements; however, the total amount of dividends that the Utilities can pay to SPR under their financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under their financing agreements is greater than the amount that the Utilities can pay under the PUCN dividend restriction. As of June 30, 2006, NPC had paid $32 million in dividends to SPR and SPPC had paid $16 million in dividends to SPR.

Limitations on Indebtedness

The terms of SPR’s $335 million 8.625% Senior Unsecured Notes due March 15, 2014, $99 million 7.803% Senior Unsecured Notes due 2012 and $225 million 6.75% Senior Unsecured Notes due 2017 restrict SPR and any of its Restricted Subsidiaries (NPC and SPPC) from incurring any additional indebtedness unless:

1. 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, or

2. the debt incurred is specifically permitted under the terms of the respective series of Senior Notes, which permits the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit supporting SPR’s or any Restricted Subsidiary’s obligations to energy suppliers, or

3. the indebtedness is incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan and SPPC’s 2004 Integrated Resource Plan.

If the respective series of Senior Notes are 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 respective series of Senior Notes remain investment grade. As of June 30, 2006, SPR, NPC and SPPC would have been able to issue approximately $279 million of additional indebtedness on a consolidated basis, assuming an interest rate of 7%, per the requirement stated in number 1 above.

Cross Default Provisions

None of the Utilities’ financing agreements contain a cross-default provision that would result in an event of default by that Utility upon an event of default by SPR or the other Utility under any of their respective financing agreements. Certain of SPR’s financing agreements, however, do contain cross-default provisions that would result in event of default by SPR upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of SPR and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time SPR or the Utilities may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPR’s and the Utilities’ various financing agreements are summarized in the 2005 Form 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sierra Pacific Resources – Liquidity and Capital Resources (SPR Consolidated),” and remain unchanged from their description in the 2005 Form 10-K.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2006, NPC recognized net income of approximately $28.5 million compared to $21 million for the same period in 2005. During the six months ended June 30, 2006, NPC recognized net income of approximately $25.2 million compared to $12.9 million for the same period in 2005. As of June 30, 2006, NPC had paid $32 million in common stock dividends to SPR.

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

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


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Operating Revenues:
Electric	$	543,869	$	451,384		20.5	%	$	925,144	$	805,518		14.9	%

Energy Costs:
Purchased power		187,093		228,254		-18.0	%		348,689		369,682		-5.7	%
Fuel for power generation		151,694		53,212		185.1	%		241,516		108,852		121.9	%
Deferral of energy costs-electric-net		30,621		8,111		277.5	%		33,788		43,934		-23.1	%

		369,408		289,577		27.6	%		623,993		522,468		19.4	%


Gross Margin	$	174,461	$	161,807		7.8	%	$	301,151	$	283,050		6.4	%

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

Electric Operating Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Electric Operating Revenues ($000):
Residential	$	250,459	$	193,300		29.6	%	$	408,354	$	336,305		21.4	%
Commercial		115,191		98,490		17.0	%		203,127		181,245		12.1	%
Industrial		163,573		137,293		19.1	%		277,528		240,624		15.3	%

Retail revenues		529,223		429,083		23.3	%		889,009		758,174		17.3	%
Other¹		14,646		22,301		-34.3	%		36,135		47,344		-23.7	%

Total Revenues	$	543,869	$	451,384		20.5	%	$	925,144	$	805,518		14.9	%


Retail sales in thousands of megawatt-hours (MWH)		5,460		4,814		13.4	%		9,461		8,602		10.0	%

Average retail revenue per MWH	$	96.93	$	89.13		8.8	%	$	93.97	$	88.14		6.6	%


¹		Primarily wholesale.

NPC’s retail revenues increased for the three months and six months ended June 30, 2006, as compared to the same periods in the prior year due to increases in retail rates, warmer weather, and customer growth. Retail rates increased as a result of NPC’s various BTER and Deferred Energy Cases (refer to Regulatory Proceedings in the 2005 Form 10-K). Retail customers increased by 5.3% and 5.1% for the three months ended and the six months ended June 30, 2006, respectively.

Based on NPC’s projected customer forecast, NPC expects the number of retail electric customers in the Clark County area to continue to grow. On June 28, 2006, NPC announced that its electric rates are expected to remain stable until 2007 following the approval of a stipulation agreement by the PUCN. The approved agreement allows full recovery by NPC of its incurred fuel and purchase power costs, but does not affect rates on August 1, 2006, because of previously approved rate changes. For further discussion on the various cases see Regulatory Proceedings, later.

Electric Operating Revenues – Other decreased for the three months and six months ended June 30, 2006 compared to the same periods in 2005, primarily due to revenues associated with Mohave which have been reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion of Mohave refer to Note 6, Commitments and Contingencies of the Notes to Financial Statements. Also contributing to the decrease were decreases in energy usage by public authority customers due to their transitioning to distribution-only services.

Purchased Power


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Purchased Power	$	187,093	$	228,254		-18	%	$	348,689	$	369,682		-5.7	%

Purchased Power in thousands of MWhs		2,599		3,329		-21.9	%		4,899		5,569		-12	%
Average cost per MWh of Purchased Power	$	71.99	$	68.57		5	%	$	71.18	$	66.38		7.2	%

NPC’s purchased power costs declined for the three months and six months ended June 30, 2006, compared to the same period in 2005, primarily due to an increase in internal generation. During the six months ended June 30, 2006, NPC began operating the Silverhawk and Lenzie generating stations. These plants provided additional generated energy, reducing the need for purchased power.

Fuel For Power Generation


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Fuel for Power Generation	$	151,694	$	53,212		185.1	%	$	241,516	$	108,852		121.9	%
Thousands of MWhs generated		3,286		1,849		77.7	%		5,215		3,735		39.6	%
Average cost per MWh of Generated Power	$	46.16	$	28.78		60.4	%	$	46.31	$	29.14		59.0	%

Fuel for power generation increased for the three and six months ended June 30, 2006 compared to the same period in 2005 due to several factors:

	•		With the addition of the Silverhawk and Lenzie generating stations it was more economical for NPC to rely more on its own generation rather than the purchase of power. As such, the increase in volume of Mwh’s generated increased significantly compared to the same periods in the prior year.

	•		The shutdown of Mohave Coal Generating station as of the beginning of the year increased the cost per Mwh of generated power. Although Silverhawk and Lenzie are highly efficient generation stations, the cost of coal is substantially lower than the cost of natural gas. Mohave generation during the six months ended June 30, 2005 represented approximately 20% of total generation.

	•		Hedging instruments purchased when gas prices were escalating as a result of the 2005 hurricanes in the southern United States increased fuel for power generation costs. The settlement of these instruments primarily during the second quarter of 2006 negatively impacted the average cost per MWh as natural gas prices were decreasing during this period.

Deferred Energy Costs — Net


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Deferred energy costs — net	$	30,621	$	8,111		277.5	%	$	33,788	$	43,934		-23.1	%

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

Amounts include amortization of deferred energy costs for the three months ended June 30, 2006 and 2005 of $31.1 million and $25.5 million, respectively; and under-collections of amounts recoverable in rates of $0.5 million and $17.4 million, respectively. Amounts for the six months ended June 30, 2006 and 2005 include amortization of deferred energy costs of $52.4 million and $72.1 million, respectively; and under-collections of amounts recoverable in rates of $18.6 million and $28.2 million, respectively.

Allowance for Funds Used During Construction (AFUDC)


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Allowance for other funds used during construction	$	2,725	$	4 ,408		-38.2	%	$	8,154	$	7,898		3.2	%

Allowance for borrowed funds used during construction	$	2,700	$	5,479		-50.7	%	$	8,072	$	9,792		-17.6	%

	$	5,425	$	9,887		-45.1	%	$	16,226	$	17,690		-8.3	%

AFUDC for NPC is lower for the three months and six months ended June 30, 2006 compared to the same periods in 2005 due to a decrease in Construction Work in Progress (CWIP). The decrease is primarily due to the completion of Blocks 1 and 2 of the Chuck Lenzie Station and Harry Allen Unit 4.

Other (Income) and Expenses


	Three Months									Six Months
	Ended June 30,									Ended June 30,
																Change
							Change from									from Prior
	2006			2005			Prior Year %			2006			2005			Year %
Other operating expense	$	47,705		$	49,112			-2.9	%	$	101,838		$	100,211			1.6	%
Maintenance expense	$	14,431		$	16,397			-11.99	%	$	28,588		$	33,352			-14.3	%
Depreciation and amortization	$	34,884		$	30,761			13.4	%	$	69,121		$	61,163			13.0	%
Interest charges on long-term debt	$	46,191		$	41,613			11.0	%	$	88,930		$	83,142			7.0	%
Interest charges-other	$	3,464		$	4,239			-18.3	%	$	7,291		$	8,571			-14.9	%
Interest accrued on deferred energy	$	(6,126	)	$	(4,216	)		45.3	%	$	(12,909	)	$	(8,741	)		47.7	%
Carrying charge for Lenzie	$	(9,135	)		—			N/A		$	(13,166	)		—			N/A
Other income	$	(4,385	)	$	(5,449	)		-19.5	%	$	(8,751	)	$	(12,362	)		-29.2	%
Other expense	$	2,338		$	1,817			28.7	%	$	4,303		$	3,393			26.8	%

Other operating expense for the three month period ending June 30, 2006 compared to the same period in 2005 decreased primarily due to the reclassification of operating expenses related to Mohave to a regulatory asset as ordered by the PUCN. For further discussion of Mohave see Note 6, Commitments and Contingencies of the Notes to Financial Statements.

Other operating expenses for the six month period ending June 30, 2006 was comparable to the same period in 2005.

The decrease in maintenance expense for the three month and six month periods ending June 30, 2006 compared to the same periods in the prior year is due to the timing of scheduled and unscheduled plant maintenance at Clark Station and at Reid Gardner in 2005; partially offset by the addition of Lenzie and Silverhawk Generating Stations in 2006.

Depreciation and amortization expenses were higher for the three months and the six months ended June 30, 2006 compared to the same period in 2005 primarily as a result of increases to plant-in-service. The increase is primarily due to purchase of the Silverhawk Generation Station and completion of the Harry Allen Unit IV.

Interest charges on Long-Term Debt increased during the three months and six months ended June 30, 2006, compared to the same period in 2005 due primarily to increases in long-term debt balances related to new debt issues in first quarter 2006 of $210 million, second quarter 2006 of $695 million and interest associated with various draws from the Long-Term Credit Facility, partially offset by debt redemptions in the second quarter of 2006 of $563 million. See Note 4, Long-Term Debt of the Notes to Financial Statements for additional information regarding long-term debt.

Interest charges-other for the three months and six months ended June 30, 2006 decreased, when compared to the same period in 2005, due to settlements in 2005 with terminated energy suppliers which reduced interest accruals for amounts owed, offset partially by higher amortization costs for the early redemption of a portion of NPC’s Series E and G General and Refunding Mortgage Notes.

NPC’s interest accrued on deferred energy costs was higher in 2006 due to higher deferred energy asset balances during the three months and six months ended June 30, 2006, when compared to the same period in 2005. See Note 3, Regulatory Actions of the Notes to Financial Statements for further discussion of deferred energy accounting issues.

Carrying charges on Lenzie for the three and six month period ended June 30, 2006 of $9.1 million and $13.2 million, respectively, represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. See Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements for discussion of the accounting for the carrying charge for Lenzie.

Other income decreased during the three months and six months ended June 30, 2006 compared to the same period in 2005 primarily due to the lower amortization of gains associated with disposition of SO2 allowances and the expiration of the amortization associated with the disposition of property.

Other expense increased during the three months and six months ended June 30, 2006 compared to the same period in 2005 due to increases in pension costs, donations and advertising expenses.

ANALYSIS OF CASH FLOWS

NPC’s cash flows increased during the six months ended June 30, 2006, when compared to the same period in 2005, due primarily to an increase in cash from financing activities offset partially by increased use of cash in operating and investing activities.

At various times within the first six months of 2006, NPC borrowed approximately $660 million under its revolving credit facility, of which approximately $535 million was repaid from the net proceeds of issuance of $905 million of NPC’s General Refunding Mortgage Notes, Series M, N and O. The remainder of the proceeds, together with the draw on the credit facility, was utilized to redeem approximately $563 million of outstanding debt and to pay associated costs, to finance net construction costs of $390 million and for operating activities. NPC also paid dividends to SPR of approximately $32 million during 2006.

Cash used by investing activities increased when compared to the same period in 2005 due primarily to the acquisition of the Silverhawk facility, offset by a reduction in spending at the Lenzie Generating Station which was placed in service in 2006.

Cash from operations decreased during the six months ended June 30, 2006, when compared to the same period in 2005, due primarily to increases in accounts receivable due to unseasonably warm weather, a decrease in collections for deferred energy balances due to the ending of collection periods, and the settlement with Enron during the first quarter. In addition, NPC’s payments in 2006 for obligations existing at December 31, 2005 to power suppliers were not offset by similar obligations at June 30, 2006 due to new generation capacity. In contrast, the payments made in 2005 for obligations existing at December 31, 2005 were offset by new and increased obligations at June 30, 2005 for the start of the summer peak.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows are electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on NPC’s outstanding indebtedness. NPC had cash and cash equivalents of approximately $54.9 million at June 30, 2006. As of June 30, 2006, NPC had approximately $268 million available under its existing revolving credit facility. Additionally, if necessary, NPC has the ability to issue additional debt, as discussed under Limitations on Indebtedness.

NPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy and external borrowings. However, to fund capital requirements, as discussed below, NPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and if necessary, the issuance of long-term debt and/or capital contributions from SPR.

During the six months ended June 30, 2006, there were no material changes to the contractual obligations described in NPC’s 2005 Form 10-K except for the certain financing transactions as discussed below.

Financing Transactions

Redemption Notices

On July 24, 2006, NPC provided a notice of redemption to the holders of its 6.6% Clark County Pollution Control Refunding Revenue Bonds, Series 1992B, due June 1, 2019, in the amount of $39.5 million. The bonds are scheduled to be redeemed on August 23, 2006 at 100% of the stated principal amount, plus accrued interest to the date of redemption.

NPC also provided notices of redemption to the holders of two series of Coconino County Pollution Control Revenue Bonds: the 5.35%, Series 1995E, due October 1, 2022, in the amount of $13 million and the 5.8%, Series 1997B, due November 1, 2032, in the amount of $20 million. Both series of bonds are also scheduled to be redeemed on August 23, 2006 at 100% of the stated principal amount, plus accrued interest to the date of redemption.

General and Refunding Mortgage Notes, Series O

•

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, and

	•		payment of related fees from the offering and for general corporate purposes

General and Refunding Mortgage Notes, Series N

	•		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.

Tender Offer for General and Refunding Mortgage Notes, Series E

On June 1, 2006, NPC commenced a tender offer for all of its 10.875% General and Refunding Mortgage Notes, Series E, due 2009. In conjunction with that offer, NPC solicited the consent of holders of a majority in aggregate principal amount of the Notes to eliminate substantially all of the restrictive covenants contained in the officer’s certificate governing the Notes. Approximately $150 million of $162.5 million Series E notes outstanding were validly tendered and accepted by NPC. Those holders who tendered the Notes and delivered their consents by June 14, 2006 were entitled to receive a consent payment of $30 per $1000 principal amount of Notes, plus tender consideration for each $1,000 principal amount of Notes validly tendered. Those holders who tendered the Notes after June 14, 2006, but prior to June 28, 2006, were entitled to receive the tender consideration only. This tender consideration was $1,038.45 in cash plus accrued and unpaid interest up to the June 29, 2006 settlement date per $1,000 principal amount of the Notes tendered. Proceeds from the June 26, 2006 issuance of Series N and Series O Notes (discussed above) were used to fund the tender offer. The total consideration (including the consent payment and accrued interest) paid on June 29, 2006 was approximately $163.6 million. As of June 30, 2006, approximately $12.5 million of the Series E notes remain outstanding.

Revolving Credit Facility

On April 19, 2006, NPC increased the size of its second amended and restated revolving credit facility expiring 2010 to $600 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of June 30, 2006, NPC had $57 million of letters of credit outstanding and had borrowed $275 million under the revolving credit facility. As of July 28, 2006, NPC had $57.8 million of letters of credit outstanding and had borrowed $325 million under the revolving credit facility.

as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of June 30, 2006, NPC was in compliance with these covenants.

The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 9, Debt Covenant Restrictions, in the Notes to Consolidated Financial Statements in the 2005 Form 10-K.

General and Refunding Mortgage Notes, Series M

Factors Affecting Liquidity

Limitations on Indebtedness

Certain factors impact NPC’s ability to issue debt:

	1.		Financial Covenants in its financing agreements

	2.		Financing Authority from the PUCN; In February 2006 NPC was authorized to enter into financings of $1.78 billion which amount includes $600 million for the revolving credit facility (described above). NPC has also issued approximately $100 million of new debt authorized under the order. NPC’s only remaining authority beyond the use of its revolving credit facility is to refinance existing debt as specified in the order.

	3.		Limits on Bondable Property; To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the General and Refunding Mortgage Indenture. As of June 30, 2006, NPC has the capacity to issue $531 million of General and Refunding Mortgage Securities.

The terms of certain SPR debt further prohibit NPC and SPPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of NPC’s Series G Notes, which mature in 2013, NPC’s Series I Notes, which mature in 2012, NPC’s Series L Notes, which mature in 2015, and NPC’s Second Amended and Restated Revolving Credit Facility restrict NPC from incurring any additional indebtedness unless certain covenants are satisfied. See Note 9, Debt Covenant Restrictions of the Notes to Financial Statements in the 2005 Form 10-K. If NPC’s Series G Notes, Series I Notes, or the Series L Notes are 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 securities remains investment grade.

As of June 30, 2006, the financial covenants under the revolving credit facility would allow NPC to issue up to $422 million of additional debt. However, the covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, at $279 million. Therefore, despite the amount of additional debt allowed under the revolving credit facility debt incurrence covenant, NPC would be limited to issuing no more than $279 million of additional debt as of June 30, 2006. Further, since NPC currently has no PUCN authority to issue new debt beyond the $600 million revolving credit facility, NPC is limited to borrowing under the credit facility. As of July 28, 2006, the balance available under the credit facility is $217 million.

The covenant limitations of certain SPR debt may allow for higher or lower borrowings than $279 million, depending on usage of the NPC and SPPC revolving credit facilities at the time of the covenant calculation.

Limitations on Ability to Issue General and Refunding Mortgage Bonds

NPC’s First Mortgage Indenture creates a first priority lien on substantially all of NPC’s properties. As of June 30, 2006, $154.5 million of NPC’s first mortgage bonds were outstanding. NPC agreed under the terms of various securities issues under its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds.

NPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of NPC’s properties in Nevada that is junior to the lien of the first mortgage indenture. As of June 30, 2006, $2.5 billion of NPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (3) above under “Limitations on Indebtedness” additional securities

may be issued under the General and Refunding Mortgage Indenture as of June 30, 2006. That amount is determined on the basis of:

	1.		70% of net utility property additions

	2.		the principal amount of retired General and Refunding Mortgage Securities, and/or

	3.		the principal amount of first mortgage bonds retired after October 19, 2001.

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

Cross Default Provisions

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

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended June 30, 2006, SPPC recognized net income of approximately $9 million compared to net income of approximately $4.9 million for the same period in 2005. During the six months ended June 30, 2006, SPPC recognized net income of approximately $22.3 million compared to a net income of approximately $17 million for the same period in 2005. As of June 30, 2006, SPPC had paid $16 million in common stock dividends to SPR and paid $975 thousand in dividends to holders of its preferred stock.

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

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


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Operating Revenues:
Electric	$	244,022	$	217,199		12.3	%	$	482,794	$	444,209		8.7	%
Gas		33,297		32,136		3.6	%		120,022		99,674		20.4	%


		277,319	$	249,335		11.2	%		602,816		543,883		10.8	%


Energy Costs:
Purchased Power	$	69,608	$	70,365		-1.1	%	$	161,756	$	149,089		8.5	%
Fuel for Power generation		62,474		54,626		14.4	%		115,761		108,988		6.2	%
Deferral of energy costs-electric-net		22,328		5,530		303.8	%		23,233		9,823		136.5	%
Gas purchased for resale		24,352		23,024		5.8	%		91,748		76,504		19.9	%
Deferral of energy costs-gas-net		1,353		1,332		1.6	%		6,084		1,004		506.0	%

		180,115		154,877		16.3	%		398,582		345,408		15.4	%

Energy Costs by Segment:
Electric		154,410		130,521		18.3	%		300,750		267,900		12.3	%
Gas		25,705		24,356		5.5	%		97,832		77,508		26.2	%

		180,115		154,877		16.3	%		398,582		345,408		15.4	%


Gross Margin by Segment:
Electric	$	89,612	$	86,678		3.4	%	$	182,044	$	176,309		3.3	%
Gas	$	7,592	$	7,780		-2.4	%	$	22,190	$	22,166		0.1	%
	$	97,204	$	94,458		2.9	%	$	204,234	$	198,475		2.9	%

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

Electric Operating Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior year %			2006		2005		Prior year %
Electric Operating Revenues:
Residential	$	68,217	$	58,559		16.5	%	$	150,581	$	132,132		14.0	%
Commercial		91,404		75,724		20.7	%		173,238		148,267		16.8	%
Industrial		75,957		77,302		-1.7	%		142,317		150,638		-5.5	%

Retail		235,578		211,585		11.3	%		466,136		431,037		8.1	%
Other¹		8,444		5,614		50.4	%		16,658		13,172		26.5	%

Total Revenues	$	244,022	$	217,199		12.3	%	$	482,794	$	444,209		8.7	%

Retail sales in thousands of MWh		2,101		2,177		-3.5	%		4,170		4,472		-6.8	%

Average retail revenue per MWh	$	112.13	$	97.19		15.4	%	$	111.78	$	96.39		16.0	%


¹		Primarily wholesale.

SPPC’s retail revenues increased for the three months and six months ended June 30, 2006 as compared to the same periods in the prior year primarily due to increases in retail rates and to a lesser extent customer growth. Retail rates increased as a result of SPPC’s various BTER and Deferred Energy cases (refer to “Regulatory Proceedings”). Also contributing to the increase was the growth in retail customers for the three months and six months ended June 30, 2006 (3.1% and 2.9%, respectively). These increases were slightly offset by lower industrial energy revenues and MWh’s as a result of SPPC’s largest industrial customer, Barrick Gold, moving to distribution-only services effective December 1, 2005.

On June 7, 2006, SPPC announced that its electric rates in northern Nevada are expected to remain stable for the remainder of 2006, following the approval of a settlement agreement with the PUCN. The approved settlement agreement allows full recovery by SPPC of its incurred fuel and purchase power costs, but does not affect rates on July 1, 2006, because of previously approved rate changes. On April 3, 2006, SPPC filed with the California Public Utilities Commission (CPUC) to recover $11.2 million in fuel and purchased power costs under the Energy Cost Adjustment Clause. The CPUC is expected to conduct hearings into SPPC’s request, and a decision should be made by the fourth quarter of 2006.

The increase in Electric Operating Revenues – Other for the three and six months ended June 30, 2006 compared to the same periods in 2005, was primarily due to the amortization of impact charges resulting from Barrick becoming a distribution-only services customer.

Gas Operating Revenues


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior year %			2006		2005		Prior year %
Gas Operating Revenues:
Residential	$	18,244	$	16,575		10.1	%	$	67,533	$	54,094		24.8	%
Commercial		8,995		7,857		14.5	%		31,738		26,477		19.9	%
Industrial		3,997		3,399		17.6	%		11,748		9,122		28.8	%

Retail revenue		31,236		27,831		12.2	%		111,019		89,693		23.8	%
Wholesale revenue		1,351		3,588		-62.3	%		7,500		8,608		-12.9	%
Miscellaneous		710		717		-1.0	%		1,503		1,373		9.5	%
Total Revenues	$	33,297	$	32,136		3.6	%	$	120,022	$	99,674		20.4	%


Retail sales in thousands of decatherms		2,339		2,753		-15.0	%		8,680		9,152		-5.2	%

Average retail revenues per decatherm	$	13.35	$	10.11		32.1	%	$	12.79	$	9.80		30.5	%

SPPC’s retail gas revenues increased for the three months and six months ended June 30, 2006 primarily due to increases in retail rates and customer growth, partially offset by warmer temperatures. Retail rates increased as a result of SPPC’s various general, energy and deferred energy rate cases (refer to “Regulatory Proceedings”). Also contributing to the increase was the growth in retail customers for the three months and six months ended June 30, 2006 (4.5% and 4.3%, respectively). On May 15, 2006, SPPC filed an application with the PUCN to implement a new deferred energy account adjustment in order to recover natural gas costs and to reset the BTER. If approved by the PUCN, SPPC has requested rates to become effective December 2006.

The wholesale revenues for the three months and six months ended June 30, 2006, decreased compared to the same period of 2005 primarily due to decreased availability of gas for wholesale sales.

Purchased Power


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Purchased Power	$	69,608	$	70,365		-1.1	%	$	161,756	$	149,089		8.5	%

Purchased Power in thousands of MWhs		1,395		1,379		1.2	%		2,704		2,779		-2.7	%
Average cost per MW of Purchased Power	$	49.90	$	51.03		-2.2	%	$	59.82	$	53.65		11.5	%

Purchased power costs remained comparable for the three months ended June 30, 2006 compared to the same period in 2005. For the six months ended June 30, 2006 purchased power costs increased compared to the same period in 2005

primarily due to higher prices of purchased power. Volumes for the six months ended June 30, 2006 decreased slightly due to a large industrial customer transitioning to distribution only services which was partially offset by an increase in the purchase of power as a result of the planned outage of the SPPC Valmy Units 1 and 2 Coal Generating Plant.

Fuel For Power Generation


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Fuel for Power Generation	$	62,474	$	54,626		14.4	%	$	115,761	$	108,988		6.2	%

Thousands of MWh generated		821		1,018		-19.4	%		1,787		2,089		-14.5	%
Average fuel cost per MWh of Generated Power	$	76.10	$	53.66		41.8	%	$	64.78	$	52.17		24.2	%

Fuel for power generation and the average fuel cost per MWh increased for the three months and six months ended June 30, 2006 compared to the same period in 2005. The increase is primarily related to increases in natural gas and coal prices, during the first quarter of 2006 and hedging instruments purchased when gas prices were escalating as a result of the 2005 hurricanes in the southern United States, which increased the average cost of fuel for power generation. The settlement of these instruments primarily during the second quarter of 2006 negatively impacted the average cost per MWh as natural gas prices were decreasing during this period. MWh’s generated decreased as compared to 2005 due to the Valmy Unit 1 and Unit 2 Coal Plant planned outage in the second quarter of 2006 and a large industrial customer transitioning to distribution only service for 2006.

Gas Purchased for Resale


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Gas Purchased for Resale	$	24,352	$	23,024		5.8	%	$	91,748	$	76,504		19.9	%

Gas Purchased for Resale (in thousands of decatherms)		2,549		3,028		-15.8	%		10,006		10,387		-3.7	%

Average cost per decatherm	$	9.55	$	7.60		25.7	%	$	9.17	$	7.37		24.4	%

The cost of gas purchased for resale for the three months ended June 30, 2006 as compared to the same period in 2005 increased primarily due to hedging instruments purchased when gas prices were escalating as a result of the 2005 hurricanes in the southern United States partially offset by a decrease in volume. The three months ended June 30, 2005 had colder winter weather that continued through May resulting in increased resale volumes.

The cost of gas purchased for resale for the six months ended June 30, 2006 as compared to the same period in 2005 increased primarily due to higher natural gas prices in the first quarter of 2006, which is typically SPPC’s peak season for its gas operations.

Deferred Energy Costs


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Deferred energy costs — electric — net	$	22,328	$	5,530		303.8	%	$	23,233	$	9,823		136.5	%
Deferred energy costs — gas — net		1,353		1,332		1.6	%		6,084		1,004		506.0	%

	$	23,681	$	6,862		245.1	%	$	29,317	$	10,827		170.8	%

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

Deferred energy costs — electric net includes amortization of deferred energy costs for the three months ended June 30, 2006 and 2005 of $11.3 million and $9.5 million, respectively; an over-collection of amounts recoverable in rates of $11.0 million and an under-collection of amounts recoverable in rates of $4.0 million, respectively. Amounts for the six months ended June 30, 2006 and 2005 include amortization of deferred energy costs of $22.6 million and $18.7 million, respectively; and an over-collection of amounts recoverable in rates of $.6 million and an under-collection of amounts recoverable in rates of $8.9 million, respectively.

Deferred energy costs — gas — net for 2006 and 2005 include amortization of deferred energy costs for the three months ended June 30, 2006 of $1.1 million and $(0.2) million, respectively; and an over-collection of amounts recoverable in rates of $0.2 million and $1.5 million, respectively. Amounts for the six months ended June 30, 2006 include amortization of deferred energy costs of $4.2 million and $(0.6) million, respectively; and an over-collection of amounts recoverable in rates of $1.9 million and $1.6 million, respectively.

Allowance for Funds Used During Construction (AFUDC)


	Three Months							Six Months
	Ended June 30,							Ended June 30,
					Change from							Change from
	2006		2005		Prior Year %			2006		2005		Prior Year %
Allowance for other funds used during construction	$	1,449	$	481		201.2	%	$	2,152	$	800		169.0	%

Allowance for borrowed funds used during construction	$	1,307	$	449		191.1	%	$	1,937	$	739		162.1	%

	$	2,756	$	930		196.3	%	$	4,089	$	1,539		165.7	%

AFUDC for SPPC is higher for the three months and six months ended June 30, 2006 compared to the same periods in 2005 due to an increase in Construction Work-In-Progress (CWIP). The increase is primarily due to the expansion of the Tracy Generating Station.

Other (Income) and Expense


	Three Months									Six Months
	Ended June 30,									Ended June 30,
							Change from									Change from
	2006			2005			Prior Year %			2006			2005			Prior Year %
Other operating expense	$	33,119		$	33,769			-1.9	%	$	67,294		$	68,538			-1.8	%
Maintenance expense	$	8,995		$	7,760			15.9	%	$	16,768		$	13,751			21.9	%
Depreciation and amortization	$	21,738		$	22,537			-3.5	%	$	44,962		$	44,924			0.1	%
Interest charges on long-term debt	$	18,134		$	17,319			4.7	%	$	35,824		$	34,626			3.5	%
Interest charges-other	$	1,257		$	1,255			0.2	%	$	2,353		$	2,401			-2.0	%
Interest accrued on deferred energy	$	(1,512	)	$	(1,693	)		-10.7	%	$	(3,445	)	$	(3,276	)		5.2	%
Other income	$	(2,662	)	$	(1,496	)		77.9	%	$	(4,810	)	$	(2,467	)		95	%
Other expense	$	2,144		$	1,593			34.6	%	$	4,668		$	3,233			44.4	%

Other operating expense for the three month and six month periods ending June 30, 2006 was comparable to the same period in 2005.

Maintenance costs for the three month and six month periods ending June 30, 2006 increased from the prior year due to the timing of scheduled and unscheduled plant maintenance at Valmy and Tracy.

Depreciation and amortization expenses for the three months ended June 30, 2006 were lower due to the change in depreciation rates as ordered by the PUCN in SPPC’s General Electric and Gas Rate Case. For further information on SPPC’s General and Electric Rate Case see Regulatory Proceedings, later.

Interest charges on Long-Term Debt increased for the three months and six months ended June 30, 2006 compared to the same period in 2005 due primarily to interest on the $300 million Series M Note issued in March 2006, partially offset by debt redemptions in March 2006 of $188 million and an additional debt redemption in April 2006 of $10 million. See Note 4, Long-Term Debt of the Notes to Financial Statements for additional information regarding long-term debt.

Interest charges-other for the three months and six months ended June 30, 2006 was comparable to the same periods in 2005.

SPPC’s interest accrued on deferred energy costs for the three months and six months ended June 30, 2006 was comparable to the same periods in 2005.

SPPC’s other income increased during the three months and six months ended June 30, 2006, when compared to the same period in 2005, primarily due to an increase in interest income associated with higher cash balances from the issuance of new debt in March, as well as gains from the sale of property.

SPPC’s other expense increased during the three months and six months ended June 30, 2006, when compared to the same period in 2005, due primarily to non-utility lease expenses, donations, advertising and pension costs.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows decreased during the six months ended June 30, 2006 compared to the same period in 2005 as a result of an increase in cash used in investing activities offset by increases in cash flows from operating and financing activities.

Cash used by investing activities increased primarily as a result of the expansion of the Tracy plant.

At various times within the first six months in 2006, SPPC borrowed approximately $198 million under its revolving credit facility and also issued $300 million 6.0% General and Refunding Mortgage Notes Series M. The draw on the credit facility was used to retire approximately $198 million of SPPC’s Medium Term Series A, B and C Notes, and the net proceeds of the $300 million offering were used to pay off the amount borrowed under the revolving credit facility, to redeem $50 million of preferred stock and to pay associated costs, premium and dividends. The balance will be used to redeem $20 million in maturing debt. SPPC also paid dividends to SPR of approximately $16 million. Cash from operating activities were higher in

2006 mainly due to the settlement of balances outstanding for tax sharing agreements and a reduction in prepayments for energy, offset by the settlement with Enron during the first quarter.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows are electric and gas revenues, including the recovery of previously deferred energy and gas costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on SPPC’s outstanding indebtedness. SPPC had cash and cash equivalents of approximately $77.8 million at June 30, 2006. As of June 30, 2006, SPPC had approximately $340 million available under its existing revolving credit facility. Additionally, if necessary, SPPC has the ability to issue additional debt, as discussed under Limitations on Indebtedness.

SPPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy. However, to fund capital requirements, as discussed in the 2005 Form 10-K, SPPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility, and if necessary, the issuance of long-term debt and/or capital contributions from SPR.

During the six months ended June 30, 2006, there were no material changes to the contractual obligations described in SPPC’s 2005 Form 10-K except for certain financing transactions as discussed below and the entering into certain equipment and construction service contracts to build SPPC’s 514 MW combined cycle natural gas power plant at its Tracy Generating Station, which is expected to be completed in 2008. Obligations under the contracts total approximately $329 million.

Financing Transactions

Revolving Credit Facility

On April 19, 2006, SPPC increased the size of its amended and restated revolving credit facility expiring 2010 to $350 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of June 30, 2006, SPPC had $10.3 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility. As of July 28, 2006, SPPC had $10.3 million of letters of credit and had no amounts borrowed under the revolving credit facility.

General and Refunding Mortgage Notes, Series M

	•		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,

	•		payment 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,

	•		payment 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 $.4875 per share

The remaining $51 million of proceeds have been or will be used as follows:

	•		payment for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.62% to 6.65% Series C notes due November 2006; and

	•		payment of related fees and for general corporate purposes.

Factors Affecting Liquidity

Limitations on Indebtedness

Certain factors impact SPPC’s ability to issue debt:

	1.		Financial Covenants in its financing agreements;

	2.		Financing Authority from the PUCN; In February 2006 SPPC was authorized to enter into financings of $1.36 billion which amount includes $350 million for the revolving credit facility (described above). SPPC has also issued $21 million of new debt. SPPC’s remaining authority beyond the use of its revolving credit facility is to issue $349 million in new debt and to refinance existing debt as specified in the order.

	3.		Limits on Bondable Property; To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the General and Refunding Mortgage Indenture. As of June 30, 2006, SPPC has the capacity to issue $144 million of General and Refunding Mortgage Securities.

The terms of certain SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of SPPC’s Series H Notes and SPPC’s Amended and Restated Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless certain covenants are satisfied. See Note 9, Debt Covenant Restrictions, of the Notes to Financial Statements in the 2005 Form 10-K.

As of June 30, 2006, the financial covenants under the revolving credit facility would allow SPPC to issue up to $868 million of additional debt. However, the covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, at $279 million. Therefore, despite the amount of additional debt allowed under the revolving credit facility debt incurrence covenant, SPPC would be limited to issuing no more than $279 million of additional debt as of June 30, 2006.

Limitations on Ability to Issue General and Refunding Mortgage Bonds

SPPC’s First Mortgage Indenture creates a first priority lien on substantially all of SPPC’s properties in Nevada and California. As of June 30, 2006, $289.3 million of SPPC’s first mortgage bonds were outstanding. SPPC agreed under the terms of various securities issued under its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds.

SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s properties in Nevada that is junior to the lien of the first mortgage indenture. As of June 30, 2006, $1.2 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (3) above under “Limitations on Indebtedness” additional securities may be issued under the General and Refunding Mortgage Indenture as of June 30, 2006. That amount has been determined on the basis of:

	1.		70% of net utility property additions

	2.		the principal amount of retired General and Refunding Mortgage Securities, and/or

	3.		the principal amount of first mortgage bonds retired after October 19, 2001.

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

Cross Default Provisions

SPPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by SPPC upon an event of default by SPR or NPC under any of their respective financing agreements. Certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

REGULATORY PROCEEDINGS (UTILITIES)

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

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

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

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies. The following regulatory proceedings have affected, or are expected to affect the utilities financial positions, results of operations and cash flows.

The Utilities are required to file periodic Deferred Energy Accounting Adjustment (DEAA) cases and General Rate Cases (GRC’s) in Nevada. As of June 30, 2006, NPC’s and SPPC’s balance sheet included approximately $362 million and $88.2 million, respectively, of deferred energy costs, $2.6 million of which have been requested in SPPC’s 2006 gas operations Deferred Energy case discussed below. As of June 30, 2006, recovery of approximately $224.1 million and $53.5 million of the $362 million and $88.2 million has been previously approved for collection over various periods. The remaining amounts will be requested in future regulatory filings. Refer to Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements.

The following summarizes rate case applications filed in 2005 and 2006. Each of these rate cases, as well as other regulatory matters such as, the Utilities’ Integrated Resource Plans and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail within this section.

Pending Rate Cases

	•		SPPC 2006 Gas Deferred Energy and BTER Update — Application to create a new Deferred Energy Accounting Adjustment (DEAA) rate and to update the going forward Base Tariff Energy Rate (BTER) for natural gas sales. The application requests December 1, 2006 increases to a) begin collecting $2.5 million of deferred natural gas costs and b) increase the natural gas BTER for going forward gas costs such that an estimated $24.5 million of new revenues will be generated annually. Combined with the expiration of a previous DEAA rate, which is expected to have fully collected its associated deferred balance before December 1, 2006, the requested rate increases total approximately 10%.

	•		SPPC 2006 California Energy Cost Adjustment Clause Rate Case – Application to reset energy rates for SPPC’s California customers. The total request seeks to collect an additional $11.2 million annually for deferred and going forward costs related to fuel and power purchases. The two requested rate increases total 17.5%. If the CPUC approves the application, SPPC expects the new rates will become effective in the latter part of 2006.

•

SPPC 2005 California General Rate Case (GRC) — Application to reset General Rates. The parties negotiated a settlement, which calls for a $4.1 million increase. SPPC anticipates the CPUC will rule in August and the rates to become effective in September 2006.

Recently Approved Rate Cases

	•		NPC 2006 BTER Update and Deferred Energy Rate Case — Application to create a new DEAA rate and to update the going forward BTER. On April 12, 2006, the PUCN approved a new BTER, which would increase purchased fuel and power revenues by an estimated $112 million. On June 28, 2006, the PUCN approved a negotiated settlement of the Deferred Energy phase of the case, which, based on an updated forecast, reduced the previously approved BTER revenue by approximately $1.6 million and allowed full recovery of $171.5 million in deferred costs.

	•		SPPC December 2005 Electric Deferred Energy and BTER Update — Application to create a new electric DEAA rate and to update the electric BTER. On April 12, 2006, the PUCN approved a new Electric BTER, which will increase purchased fuel and power revenues by an estimated $31 million. On June 7, 2006, the PUCN approved a negotiated settlement, which granted SPPC full recovery of the deferred costs during a two year period beginning July 1, 2006.

	•		SPPC 2005 Electric General Rate Case – On April 27, 2006, the PUCN authorized a 10.6% ROE and 8.96% ROR and ordered SPPC to reduce general revenues for electric services by approximately $14 million.

	•		SPPC 2005 Gas General Rate Cases – On April 27, 2006, the PUCN authorized a 10.6% ROE and 7.98% ROR and ordered SPPC to increase general revenues for gas services by approximately $4.5 million.

Nevada Matters

Nevada Power Company

2006 Integrated Resource Plan

On June 30, 2006, NPC filed its 2006 triennial Integrated Resource Plan with the PUCN. The filing requests approval to develop new conventional generation resources, new renewable generation resources, improve NPC’s transmission system and increase demand side initiatives. The demand side programs are intended to help customers use electricity more efficiently and also contribute to NPC’s Renewable Portfolio requirements. The filing contains the following key elements:

•

Requests approval to construct the following supply side resources:

	°		Two 750 MW coal fired generation units at the proposed Ely Energy Center in White Pine County, Nevada to be on line in 2011 and 2013. 80% of the unit capacity is to be assigned to NPC and 20% to SPPC.

	°		A 250-mile 500 kV transmission line to integrate the new generation into both NPC’s and SPPC’s systems and to allow delivery of geothermal resources from Northern Nevada to NPC and solar powered generation located in Southern Nevada to SPPC.

	°		Requests the PUCN to designate the above facilities as critical facilities under Nevada regulations and requests incentive ratemaking treatment including “CWIP in rate base” during construction and, upon completion, a 2% enhanced ROE and accumulation of depreciation expense in a regulatory asset account from the time the plants are placed in service until they are included in rates.

	°		600 MW of gas fired combustion turbines, 400MW on line in 2008 and 200 MW on line in 2009

	•		Outlines initiatives, including NPC ownership positions in renewable energy projects, which are expected to enable NPC to meet Nevada’s Renewable Portfolio Standards

	•		Requests approval of four new demand side programs and to increase spending on eight existing demand side programs

	•		Outlines NPC’s ten-year $4.7 billion budget for all of the proposed initiatives

2006 Deferred Energy and BTER Update

On January 17, 2006, NPC filed a DEAA rate case application with the PUCN seeking recovery for purchased fuel and power costs and to increase its going forward BTER to reflect future energy costs. Refer to the 2005 Form 10-K for specific details about this filing.

previous DEAA rate case. Combined, the $120 million increase represented an overall average rate increase of approximately 6.5%.

In the Deferred Energy portion of the case, NPC had requested authorization to recover $171.5 million of previously incurred purchased fuel and power costs during a one year period. On June 28, 2006, the PUCN approved a negotiated settlement, which specified (1) a reduction of $1.6 million to the BTER approved on April 12, 2006 based on an updated projection of costs and (2) granted NPC full recovery of the $171.5 million of deferred costs during a two year period beginning August 1, 2006, however the $171.5 million was reduced by a $16.5 million payment previously received by NPC in connection with the Lenzie acquisition. The agreement structured the cost recovery such that no rate increase was required. The DEAA rates required to recover the deferred balance are scheduled to occur during a two year period such that they will be offset by the expiration of previously approved DEAA rates.

Enhanced ROE Due to Early Completion of Lenzie Generating Station

The PUCN designated the Lenzie Generating Station a critical facility and allowed a 2% enhancement to the authorized ROE when the PUCN approved NPC’s request to acquire the facility. The PUCN further allowed up to an additional .5% enhanced ROE if the Lenzie Block #1 generator units (two combustion turbine/generators and one steam turbine/generator) were commercially operable before March 31, 2006 and another .5% ROE enhancement if Block #2 was completed before June 30, 2006.

On January 29, 2006, the first 600MW combined cycle unit (Block #1) was declared commercially operable. On April 17, 2006, NPC announced that Lenzie Block #2 was commercially operable. NPC’s construction costs are projected to be less than the amount authorized by the PUCN. NPC believes it is eligible to receive a 3% enhancement to the otherwise authorized ROE that will be decided as a result of its GRC filing to be made November 2006. See Note 1, Summary of Significant Accounting Policies for further discussion on the accounting for the enhancement.

Material Amendments to NPC’s 2003 Integrated Resource Plan

Request for Authorization to Acquire Land & Land Rights for Transmission Facilities

On January 20, 2006, NPC filed an amendment to its 2003 Integrated Resource Plan requesting approval to acquire approximately $57 million of strategic investments in land and land rights necessary for future 500 kV and 230 kV transmission facilities. NPC also requested approval to accrue a carrying charge on the investments, which would be equal to the current Allowance for Funds Used During Construction.

On April 26, 2006, the PUCN approved a negotiated agreement that authorizes NPC to invest $37 million in land and land rights and to include authorized investments in the rate base calculation for its next general rate case.

Sierra Pacific Power Company

Material Amendments to SPPC’s 2004 Integrated Resource Plan

On June 14, 2006, SPPC filed an amendment to its 2004 Integrated Resource Plan. The filing contained the following key elements:

•

Requests approval to construct the following supply side resources:

	°		Two 750 MW coal fired generation units at the proposed Ely Energy Center in White Pine County, Nevada to be on line in 2011 and 2013. Twenty percent of the unit capacity is to be assigned to SPPC and eighty percent to NPC.

	°		A 500 kV transmission line to integrate the new generation into both NPC’s and SPPC’s systems and to allow delivery of geothermal resources from Northern Nevada to NPC and solar powered generation located in Southern Nevada to SPPC.

	°		Requests the PUCN to designate the above facilities as critical facilities under Nevada regulations and requests incentive ratemaking treatment including “CWIP in rate base” during construction and, upon completion, a 2% enhanced ROE and accumulation of depreciation expense in a regulatory asset account from the time the plants are placed in service until they are included in rates.

	•		Requests approval to make various enhancements to SPPC’s existing fleet of generators.

	•		Provides a $3.7 billion total estimate for the Ely Energy Center and outlines SPPC’s cost for other proposed initiatives totaling approximately $15 million.

2006 Natural Gas Deferred Energy and BTER Update

December 2005 Electric Deferred Energy and BTER Update

2005 Electric and Gas General Rate Cases

On October 3, 2005, SPPC filed a gas general rate case along with its statutorily required electric general rate case. Refer to SPR’s 2005 Form 10-K for specific details about this filing.

On April 27, 2006, the PUCN issued its order to change electric and gas general rates. Although the order differed from our requested filing, the changes did not require material adjustments to net income for the six months ended June 30, 2006. The PUCN vote resulted in the following significant items:

	•		Electric general revenue decrease: approximately $14 million annually or 1.5% effective May 1, 2006

	•		Gas general revenue increase: $4.5 million annually or 2.3%, effective May 1, 2006

	•		Electric Return on Equity and Rate of Return: 10.6% and 8.96% respectively

	•		Gas Return on Equity and Rate of Return: 10.6% and 7.98% respectively

	•		Approval to continue recovery of SPPC’s allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Electric customers

	•		Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Gas customers

	•		New depreciation rates for Gas and Electric facilities

	•		Deferred recovery of legal expenses related to the Enron purchased power contract litigation

Other Nevada Matters

Nevada Power Company and Sierra Pacific Power Company Renewable Portfolio Compliance

In April 2006, the Utilities filed their 2005 Annual Renewable Energy Portfolio Standard Report with the PUCN (the “Report”). The Report indicates that the Utilities will meet the non-solar portfolio standard upon PUCN approval of a sale from SPPC to NPC of non-solar portfolio energy credits. The Utilities requested an exemption from the PUCN for the solar portion of the portfolio standard.

Pursuant to regulations, the PUCN has set the matter for hearing. Past filings have not resulted in monetary fines, but the PUCN regulations allow for administrative fines when utilities have not complied with the renewable portfolio standard. At this time, management cannot predict the amount of monetary fines, if any; however, management does not believe the monetary fines would be material. The Utilities continue to work with the PUCN and renewable energy suppliers to achieve compliance with the portfolio standard.

California Electric Matters (SPPC)

Sierra Pacific Power Company 2006 Energy Cost Adjustment Clause Rate Case

On April 3, 2006, SPPC filed with the CPUC to reset its “balancing” rate to recover a forecasted deferred energy cost balance and to increase its “offset” rate for going-forward fuel and power purchases. The requested increase in the balancing rate is expected to result in $1.1 million additional revenue and the requested increase in the offset rate is expected to collect an additional $10.1 million. The total request represents an $11.2 million annual revenue increase or a 17.5% average increase to customer rates.

On May 11, 2006, a pre-hearing conference was held and a procedural schedule was established. Evidentiary hearings have been set for September 12-14, 2006 with a proposed decision expected by mid October. If approved, SPPC anticipates it will begin recovering these deferred costs in the fourth quarter of 2006.

Sierra Pacific Power Company 2005 General Rate Case

On June 3, 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue from approximately 40,000 California customers. The request represents a 12.7% average increase. SPPC requested that the new rates become effective on January 1, 2006.

California’s Division of Ratepayer Advocates filed testimony proposing to reduce SPPC’s revenue increase to $1.8 million and The Utility Reform Network proposed a $7.8 million increase. A large customer coalition group and the Western Manufactured Housing Communities Association filed testimony proposing modifications to SPPC’s rate design.

On January 24, 2006, the parties presented a negotiated settlement to a CPUC Administrative Law Judge calling for a $4.1 million revenue increase. SPPC anticipates the CPUC will rule on the settlement in August 2006. The earliest rates will become effective is September 1, 2006.

ACCOUNTING MATTERS

Recent Pronouncements

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

Financial Accounting Standards Board (FASB) Exposure Draft Regarding Defined Benefit Post-Retirement Plans

In March 2006, the FASB issued an Exposure Draft “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132-(R).” This proposed amendment seeks to address certain important deficiencies the FASB finds in today’s pension accounting. Currently, changes in a plan’s assets and its benefit obligation are not being recognized as they occur and important information about postretirement plans is currently being relegated to the footnotes rather than being recognized in the financial statements. Specifically, the amendment would require SPR and the Utilities to recognize the overfunded or underfunded status of defined benefit postretirement plans in their Consolidated Balance Sheets. An overfunded status would result in the recognition of an asset and an underfunded status would result in the recognition of a liability. The adjustment to record an asset or liability would result in an expense or benefit to accumulated other comprehensive income (a component of common stockholders’ equity). If SPR and/or the Utilities were required to record a substantial liability, it could, depending upon the magnitude thereof, affect the ability of SPR and/or the Utilities to meet certain financial covenants and incurrence tests. The FASB has indicated that it expects to issue a final statement in the third quarter of 2006 and that the statement would be effective for fiscal years ending after December 15, 2006, which would be the year ended December 31, 2006, for SPR and the Utilities. SPR and the Utilities are currently reviewing the provisions of the Exposure Draft to determine the impact it may have on SPR and the Utilities’ financial position and results of operations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2006, SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).


	Expected Maturity Date
																						Fair
	2006			2007			2008			2009			2010			Thereafter			Total			Value
Long-term Debt
SPR
Fixed Rate	$	—		$	—		$	—		$	—		$	—		$	659,142		$	659,142		$	662,833
Average Interest Rate		—			—			—			—			—			7.86	%		7.86	%

NPC
Fixed Rate	$	8		$	17		$	13		$	12,554		$	—		$	2,233,335		$	2,245,927		$	2,222,306
Average Interest Rate		8.17	%		8.17	%		8.17	%		10.88	%		—			6.82	%		6.84	%
Variable Rate	$	—		$	—		$	—		$	15,000		$	275,000		$	100,000		$	390,000		$	390,000
Average Interest Rate											3.20	%		5.99	%		3.20	%		5.17	%

SPPC
Fixed Rate	$	21,044		$	2,400		$	322,400		$	600		$	—		$	749,250		$	1,095,694		$	1,087,342
Average Interest Rate		6.62	%		6.40	%		7.99	%		6.40	%		—			6.09	%		6.66	%


Total Debt	$	21,052		$	2,417		$	322,413		$	28,154		$	275,000		$	3,741,727		$	4,390,763		$	4,362,481

Commodity Price Risk

See the 2005 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2005.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $55.4 million as of June 30, 2006 and was comparable to the same period in the prior year. In the event that the trading counterparties are unable to deliver under their contracts, it may be necessary for the Utilities to purchase alternative energy at a higher market price.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

SPR, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934), have concluded that, as of June 30, 2006, the registrants’ disclosure controls and procedures were effective.

(b) Change in internal controls over financial reporting.

There were no changes in internal controls over SPR, NPC or SPPC’s financial reporting in the second quarter of 2006 that have materially affected, or are reasonably likely to materially affect their respective internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

For additional information regarding various pending administrative and judicial proceedings involving regulatory, environmental and other matters, which information is incorporated by reference into this Part II, see:

	•		“Item 3, Legal Proceedings” in the 2005 Form 10-K and Form 10-Q for the Quarter Ended March 31, 2006; and

	•		Note 6 “Commitments and Contingencies of the Condensed Notes to the Consolidated Financial Statements” in Part I of this report.

Nevada Power Company 2001 Deferred Energy Case

Sierra Pacific Power Company

Piñon Pine

ITEM 1A RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to SPR on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item1A, “Risk Factors,” of our 2005 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

If NPC and/or SPPC do not receive favorable rulings in the deferred energy applications that they file with the PUCN and they are unable to recover their deferred purchased power, gas and fuel costs, we will experience an adverse impact on cash flow and earnings. Any significant disallowance of deferred energy charges in the future could materially adversely affect our cash flow, financial condition and liquidity.

The rates that the Utilities charge their customers and certain aspects of their operations are subject to the regulation of the PUCN, which significantly influences the Utilities’ operating environment and affects their ability to recover costs from their customers. Under Nevada law, purchased power, gas and fuel costs in excess of those included in base rates are deferred as an asset on their balance sheets and are not shown as an expense until recovered from their retail customers. The Utilities are required to file deferred energy applications with the PUCN at least once every twelve months so that the PUCN may verify the prudence of the energy costs and allow them to clear their deferred energy accounts. Nevada law also requires the PUCN to act on these cases within a specified time period. Any of these costs determined by the PUCN to have been imprudently incurred cannot be recovered from the Utilities’ customers. Past disallowances in the Utilities’ deferred energy cases have been significant.

As of June 30, 2006, NPC’s and SPPC’s unapproved deferred energy costs, including claims for terminated energy supply contracts, were $137.9 million and $34.3 million, respectively, and SPPC’s unapproved gas deferred energy costs were $343 thousand.

Material disallowances of deferred energy costs, gas costs or inadequate base tariff energy rates would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause downgrades of SPR’s and the Utilities’ securities by the rating agencies and would make it more difficult to finance operations and construction projects and to buy fuel and purchased power from third parties.

If NPC and/or SPPC do not receive favorable rulings in their future general rate cases, it will have a significant adverse effect on our financial condition, cash flows and future results of operations.

The Utilities’ revenues and earnings are subject to changes in regulatory proceedings known as general rate cases, which the Utilities file with the PUCN approximately every two years. In the Utilities’ general rate cases, the PUCN establishes, among other things, their recoverable rate base, their return on common equity, overall rate of return, depreciation rates and their cost of capital.

We cannot predict what the PUCN will direct in their orders on the Utilities’ pending or future general rate cases. Inadequate base energy rates would have a significant adverse effect on the Utilities’ financial condition and future results of operations and could cause additional downgrades of their securities by the rating agencies and make it significantly more difficult to finance operations and construction projects and to buy fuel and purchased power from third parties.

SPR and the Utilities have substantial indebtedness that they may be required to refinance. The failure to refinance indebtedness would have an adverse effect on us.

SPR and the Utilities have indebtedness that must be repaid, purchased, remarketed or refinanced. If the Utilities do not have sufficient funds from operations and/or SPR does not have sufficient funds from dividends to repay such indebtedness at maturity or when otherwise due, we will have to refinance the indebtedness through additional financings in private or public offerings. If, at the time of any financing or refinancing, prevailing interest rates or other factors result in higher interest rates on the refinanced debt, the increase in interest expense associated with the refinancing could adversely affect our cash flow, and, consequently, the cash available for payments on our other indebtedness. If the Utilities are unable to refinance or extend outstanding borrowings on commercially reasonable terms, or at all, they may have to:

	•		reduce or delay capital expenditures planned for replacements, improvements and expansions; and/or

	•		dispose of assets on disadvantageous terms, potentially resulting in losses and adverse effects on cash flow from their operating activities.

We cannot assure you that the Utilities could effect or implement any of these alternatives on satisfactory terms, if at all. If SPR or the Utilities are unable to refinance indebtedness as it matures, our cash flow, financial conditions and liquidity could be materially adversely affected.

If SPR is precluded from receiving dividends from the Utilities, its financial condition and ability to meet its debt service obligations will be materially adversely affected.

SPR is a holding company with no significant operations of its own. Its cash flows are substantially derived from dividends paid to it by the Utilities, which are typically utilized to service SPR’s debt and pay SPR’s operating expenses. In the future, subject to various factors to be considered by SPR’s Board of Directors, a portion of SPR’s cash flow may be used to resume dividend payments on SPR’s common stock, with the balance, if any, reinvested in SPR’s subsidiaries as contributions to capital. The Utilities are subject to restrictions on their ability to pay dividends to SPR under the terms of certain of their respective financing agreements and their PUCN orders. In addition, certain provisions of the Federal Power Act could, depending on the interpretation thereof, limit or prohibit the payment of dividends to SPR.

Assuming that the Utilities meet the requirements to pay dividends under the Federal Power Act and that any dividends paid to us are for SPR’s debt service obligations, the most restrictive of the dividend restrictions applicable to the Utilities individually can be found, for NPC, in NPC’s Series O Notes and, for SPPC, in SPPC’s Series H Notes. Under their material dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is less than 50% of such Utilities’ consolidated net income plus the amount of capital contributions made to such Utility by SPR for the period from the date of issuance of the respective series of Notes to the end of the most recently ended fiscal quarter. If they do not meet these conditions, the Utilities can still pay SPR’s reasonable fees and expenses, provided that each such Utility has a cash flow to fixed charge coverage ratio of at least 1.75:1 over the prior four fiscal quarters. In addition, under the most restrictive of their dividend restrictions, NPC and SPPC have a carve-out that permits them to pay up to $25 million to SPR, from the date of issuance of the applicable debt securities, regardless of whether the other conditions to paying dividends have been met. 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. The dividend restriction in the PUCN order may be more restrictive than the Utilities’ individual dividend restrictions because the PUCN dividend restriction currently limits the amount of dividends paid to SPR collectively by the Utilities to SPR’s actual cash debt service payments, which amount may be less than the aggregate amount of the Utilities’ individual dividend restrictions. For the six months ended June 30, 2006, SPR received approximately $48 million in dividends from the Utilities to meet its debt service obligations.

SPR’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly NPC and SPPC. SPR and the Utilities have the ability to issue a significant amount of additional indebtedness under the terms of their various financing agreements.

Because SPR is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing and future liabilities. SPR conducts substantially all of its operations through its subsidiaries, and thus SPR’s ability to meet its obligations under its indebtedness will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to SPR. Holders of SPR’s indebtedness will generally have a junior position to claims of SPR’s subsidiaries’ creditors, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. As of July 28, 2006, the Utilities had approximately $3.8 billion of debt outstanding. The terms of SPR’s indebtedness restrict the amount of additional indebtedness that SPR and the Utilities may issue. Based on SPR’s June 30, 2006 financial statements, assuming an interest rate of 7.0%, SPR’s indebtedness restrictions would allow SPR and the Utilities to issue up to approximately $279 million of additional indebtedness in the aggregate, unless the indebtedness being issued is specifically permitted under the terms of SPR’s indebtedness. In addition, NPC and SPPC are subject to restrictions under the terms of their various financing agreements on their ability to issue additional indebtedness.

If Federal and/or State requirements are imposed on NPC and SPPC mandating further emission reductions, including limitations on carbon dioxide (CO2) emissions.

Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. Environmental advocacy groups and regulatory agencies in the United States have also been focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature. Future changes in environmental regulations governing these pollutants could make some electric generating units uneconomical to maintain or operate. In addition, any legal obligation that would require the Utilities to substantially reduce its emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. While mandatory requirements for further emission reductions from our fossil fleet do not appear to be imminent, we continue to monitor regulatory and legislative developments in this area.

Whether SPR can procure sufficient renewable energy sources in each compliance year to comply with the Portfolio Standard for Renewable Energy.

Currently, the State of Nevada requires compliance with its Portfolio Standard for Renewable Energy, which mandates that a share of the energy delivered to Nevada retail customers come from renewable energy resources. This energy is to be provided via direct generation, saved from portfolio energy systems or realized from implementation of efficiency measures. The Utilities continue to take affirmative actions to fulfill the Portfolio Standard requirements on their system. However, the Utilities’ success in meeting the standard remain dependent on creation of new renewable energy projects, both owned or via output which is purchased from third parties, as well as maintenance of an ongoing positive climate for renewable energy development across Nevada.

SPR and the Utilities may be negatively affected by changes in accounting principles, particularly FASB’s Exposure Draft amending FASB Statements No. 87, 88, 106, and 132-(R).

Changes in accounting principles and practices required by the FASB, the SEC and/or the FERC can have a significant effect on SPR’s and the Utilities’ financial statements and results of operations.

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

The 2006 Annual Meeting of the Stockholders of Sierra Pacific Resources was held at 10:00 a.m., Pacific Daylight Time, on Monday May 1, 2006, at the Chuck Lenzie Generating Station, 11405 US Hwy. 93, Clark County, Nevada.

Two proposals were presented for stockholder consideration: (1) election of four members of the Board of Directors to serve until the Annual Meeting in 2009, and until their successors are elected and qualified; and (2) to approve an amendment to the Company’s restated Articles of Incorporation to increase the number of authorized shares of common stock from 250,000,000 to 350,000,000.

Four Directors, Mary Lee Coleman, T.J. Day, Jerry E. Herbst, and Donald D. Snyder were elected to serve three year terms expiring at the 2009 Annual Meeting of Stockholders. The proposal to amend the Company’s Restated Articles of Incorporation increasing the number of authorized shares of common stock from 250,000,000 shares to 350,000,000 shares was also approved. Directors whose term expires in 2007: James R. Donnelley, Walter M. Higgins, John F. O’Reilly. Directors whose term expires in 2008: Joseph B. Anderson, Jr., Krestine M. Corbin, Philip G. Satre, and Clyde T. Turner.

The certified voting results are shown below:


Election of Directors	For		Withheld
Mary Lee Coleman		174,542,932		1,789,726
T.J. Day		173,778,108		2,554,551
Jerry E. Herbst		174,593,794		1,738,864
Donald D. Snyder		173,815,498		2,517,160


	For		Against		Abstain
To amend the Company’s Restated Articles of Incorporation increasing the number of authorized shares of common stock from 250,000,000 to 350,000,000.		170,831,939		5,285,157		215,559

ITEM 5. OTHER INFORMATION

On August 4, 2006, Walter M. Higgins, the Chief Executive Officer of SPR, NPC and SPPC (the “Companies”) entered into an amendment (the “Amendment”) to Mr. Higgins’ existing employment agreement with the Companies, which was originally entered into on September 26, 2003 (the “Employment Agreement”). The Amendment, which extends the term of the Employment Agreement to June 1, 2008, provides that Mr. Higgins will remain in his current position as CEO and Chairman of the Board of the Companies and as President of SPR.

Under the Amendment, Mr. Higgins was granted 500,000 performance-based shares of SPR stock. Vesting on these shares of stock is subject to performance-based criteria over a twenty-three month period, commencing August 4, 2006 and ending June 1, 2008. The performance-based criteria for the stock vesting include the performance of SPR’s common stock, restoring the credit ratings of the Utilities’ senior secured debt to investment grade, the achievement of certain regulatory and litigation milestones and the restoration of a quarterly common stock dividend. All shares that are not vested by June 1, 2008 shall be cancelled and returned to SPR. All remaining unvested performance shares granted under the original Employment Agreement have been cancelled.

In the event that Mr. Higgins’ employment is terminated without cause following a change in control of the Companies prior to June 1, 2007, Mr. Higgins would receive (i) a lump sum payment equal to two times the sum of his base salary and target incentive payment; (ii) continuation of life, disability, accident and health insurance benefits for a period of 24 months immediately following termination of employment and (iii) a lump sum payment equal to the present value of the benefits he would have received had he continued to participate in SPR’s retirement plans for an additional two years. In the event that Mr. Higgins’ employment is terminated without cause following a change in control of the Companies after June 1, 2007 but prior to June 1, 2008, Mr. Higgins would receive (i) a lump sum payment equal to one times the sum of his base salary and target incentive payment; (ii) continuation of life, disability, accident and health insurance benefits for a period of 12 months immediately following termination of employment and (iii) a lump sum payment equal to the present value of the benefits he would have received had he continued to participate in SPR’s retirement plans for a additional year.

The Amendment provides that (1) if Mr. Higgins remains employed by the Companies through June 1, 2008, or (2) if Mr. Higgins resigns prior to June 1, 2008 with the consent of the Board, he shall receive his base salary through June 1, 2008, target incentive payments that have been earned but not paid, payment for vested portions of his performance-based shares through his date of separation, a life insurance policy through age 70, office space for a three year period and other de minimus benefits.

The Amendment further provides that severance, benefits and other compensation under both the Employment Agreement and the Amendment may be modified as necessary to comply with Section 409A of the Internal Revenue Code of 1986, as amended.

Finally, the Amendment allows the Companies to enter into a consulting arrangement with Mr. Higgins after the expiration of the Amendment for a period of not more than six months to assist with the transition to his successor.

ITEM 6. EXHIBITS

(a)

Exhibits filed with this Form 10-Q:

Sierra Pacific Resources:


Exhibit 3.1		Restated and Amended Articles of Incorporation of Sierra Pacific Resources.

Exhibit 10.1		Amendment to Employment Agreement for Walter M. Higgins

Nevada Power Company:


Exhibit 4.1		Registration Rights Agreement dated June 26, 2006 among Nevada Power Company, Deutsche Bank Securities Inc. and Goldman, Sachs & Co., as representatives of the initial purchasers of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036.

Exhibit 4.2		Registration Rights Agreement dated June 26, 2006 among Nevada Power Company, Deutsche Bank Securities Inc. and Goldman, Sachs & Co., as representatives of the initial purchasers of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018.

Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company


Exhibit 31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements

	Sierra Pacific Resources -

		Consolidated Balance Sheets – June 30, 2006 and December 31, 2005	3

		Consolidated Statements of Operations – Three Months and Six Months Ended June 30, 2006 and 2005	4

		Consolidated Statements of Cash Flows – Six Months Ended June 30, 2006 and 2005	5

		Consolidated Statements of Capitalization – June 30, 2006 and December 31, 2005	6

	Nevada Power Company -

		Consolidated Balance Sheets – June 30, 2006 and December 31, 2005	8

		Consolidated Statements of Operations – Three Months and Six Months Ended June 30, 2006 and 2005	9

		Consolidated Statements of Cash Flows – Six Months Ended June 30, 2006 and 2005	10

		Consolidated Statements of Capitalization – June 30, 2006 and December 31, 2005	11


	Sierra Pacific Power Company -

		Consolidated Balance Sheets – June 30, 2006 and December 31, 2005	12

		Consolidated Statements of Operations – Three Months and Six Months Ended June 30, 2006 and 2005	13

		Consolidated Statements of Cash Flows – Six Months Ended June 30, 2006 and 2005	14

		Consolidated Statements of Capitalization – June 30, 2006 and December 31, 2005	15

		Condensed Notes to Consolidated Financial Statements	16

ITEM 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
		Sierra Pacific Resources	35
		Nevada Power Company	38
		Sierra Pacific Power Company	45

ITEM 3.		Quantitative and Qualitative Disclosures about Market Risk	58

ITEM 4.		Controls and Procedures	58

PART II — OTHER INFORMATION

ITEM 1.		Legal Proceedings	59

ITEM 1A.		Risk Factors	60

ITEM 4.		Submission of Matters to a Vote of Security Holders	62

ITEM 5.		Other Information	62

ITEM 6.		Exhibits	62

Signature Page and Certifications			63
Ex-3.1 Restated and Amended Articles of Incorporation
EX-4.1 Reg. Rights Agreement Series N, dated 6/26/06
EX-4.2 Reg. Rights Agreement Series O, dated 6/26/06
Ex-10.1 Amendment to Employment Agreement for Walter M. Higgins
EX-31.1 Section 302 Certification of C.E.O.
EX-31.2 Section 302 Certification of C.F.O.
EX-32.1 Section 906 Certification of C.F.O.
EX-32.2 Section 906 Certification of C.F.O.


	Sierra Pacific Resources (Registrant)
Date: August 4, 2006	By:	/s/ Michael W. Yackira
		Michael W. Yackira
		Corporate Executive Vice President Chief Financial Officer (Principal Financial Officer)


Date: August 4, 2006	By:	/s/ John E. Brown
		John E. Brown
		Controller (Principal Accounting Officer)

	Nevada Power Company (Registrant)
Date: August 4, 2006	By:	/s/ Michael W. Yackira
		Michael W. Yackira
		Executive Vice President Chief Financial Officer (Principal Financial Officer)


Date: August 4, 2006	By:	/s/ John E. Brown
		John E. Brown
		Controller (Principal Accounting Officer)

	Sierra Pacific Power Company (Registrant)
Date: August 4, 2006	By:	/s/ Michael W. Yackira
		Michael W. Yackira
		Executive Vice President Chief Financial Officer (Principal Financial Officer)


Date: August 4, 2006	By:	/s/ John E. Brown
		John E. Brown
		Controller (Principal Accounting Officer)