Sierra Pacific Power 10-Q 2006 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED March 31, 2006

OR

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 P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011	88-0198358	Nevada
2-28348	NEVADA POWER COMPANY 6226 West Sahara Avenue Las Vegas, Nevada 89146 (702) 367-5000	88-0420104	Nevada
0-00508	SIERRA PACIFIC POWER COMPANY P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011	88-0044418	Nevada

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.                      Yesþ  Noo (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 filerþ	Accelerated filero	Non-accelerated filero
Nevada Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filerþ
Sierra Pacific Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filerþ

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

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 May 2, 2006
Common Stock, $1.00 par value	200,879,752 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
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2006

CONTENTS

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

Sierra Pacific Resources -

Nevada Power Company -

Sierra Pacific Power Company -

 EX-4.1 Nevada Power Company Officer's Certificate

 EX-4.2 Form of Series N Notes

 EX-4.3 Registration Rights Agreement Nevada Power Company

 EX-4.4 Sierra Power Company Officer's Certificate

 EX-4.5 Form of Series M Notes

 EX-4.6 Registration Rights Agreement Sierra Pacific Power Company

 EX-10.1 Nevada Power Company Amendment and Consent

 EX-10.2 Sierra Pacific Power Company Amendment and Consent

 EX-31.1 Section 302 Certification of CEO

 EX-31.2 Section 302 Certification of CFO

 EX-32.1 Section 906 Certification of CEO

 EX-32.2 Section 906 Certification of CFO

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)
(Unaudited)

	March 31,		December 31,
	2006		2005
ASSETS
Utility Plant at Original Cost:
Plant in service	$	7,336,827	$	6,801,916
Less accumulated provision for depreciation		2,218,290		2,169,316
		5,118,537		4,632,600
Construction work-in-progress		636,416		765,005
		5,754,953		5,397,605
Investments and other property, net		62,149		62,771
Current Assets:
Cash and cash equivalents		238,966		172,682
Restricted cash and investments		—		67,245
Accounts receivable less allowance for uncollectible accounts:
2006-$36,708; 2005-$36,021		342,387		413,171
Deferred energy costs — electric (Note 1)		185,729		253,697
Deferred energy costs — gas (Note 1)		2,052		5,825
Deferred income taxes		17,469		—
Materials, supplies and fuel, at average cost		91,462		88,445
Risk management assets (Note 5)		39,609		50,226
Deposits and prepayments for energy		23,455		45,054
Other		24,986		26,544
		966,115		1,122,889
Deferred Charges and Other Assets:
Goodwill (Note 8)		22,877		22,877
Deferred energy costs — electric (Note 1)		325,496		255,312
Deferred energy costs — gas (Note 1)		5		845
Regulatory tax asset		248,353		249,261
Other regulatory assets		574,059		568,145
Risk management assets (Note 5)		298		—
Risk management regulatory assets — net (Note 5)		89,007		—
Unamortized debt issuance costs		68,375		63,395
Other		107,994		107,330
		1,436,464		1,267,165
Assets of Discontinued Operations		20,102		20,116
TOTAL ASSETS	$	8,239,783	$	7,870,546
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	2,061,378	$	2,060,154
Preferred stock		50,000		50,000
Long-term debt		4,122,580		3,817,122
		6,233,958		5,927,276
Current Liabilities:
Current maturities of long-term debt		196,325		58,909
Accounts payable		195,791		252,900
Accrued interest		69,858		58,585
Dividends declared		1,050		1,043
Accrued salaries and benefits		24,233		32,186
Current income taxes payable		—		3,159
Deferred income taxes		—		129,041
Risk management liabilities (Note 5)		98,243		16,580
Accrued taxes		5,982		6,540
Contract termination liabilities		—		129,000
Other current liabilities		58,847		56,724
		650,329		744,667
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		600,531		451,924
Deferred investment tax credit		37,815		38,625
Regulatory tax liability		37,459		38,224
Customer advances for construction		182,090		170,061
Accrued retirement benefits		84,548		77,245
Risk management regulatory liability — net (Note 5)		—		15,605
Regulatory liabilities		290,051		284,438
Other		112,802		112,281
		1,345,296		1,188,403
Liabilities of Discontinued Operations		10,200		10,200
TOTAL CAPITALIZATION AND LIABILITIES	$	8,239,783	$	7,870,546

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

3

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
OPERATING REVENUES:
Electric	$	620,047		$	581,144
Gas		86,725			67,538
Other		284			292
		707,056			648,974
OPERATING EXPENSES:
Operation:
Purchased power		253,744			220,152
Fuel for power generation		143,109			110,002
Gas purchased for resale		67,396			53,480
Deferral of energy costs — electric — net		4,072			40,116
Deferral of energy costs — gas — net		4,731			(328	)
Other		90,262			87,590
Maintenance		21,930			22,946
Depreciation and amortization		57,461			52,789
Taxes:
Income taxes		(6,899	)		(7,830	)
Other than income		11,664			11,109
		647,470			590,026
OPERATING INCOME		59,586			58,948
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,132			3,809
Interest accrued on deferred energy		8,716			6,108
Other income		13,294			10,139
Other expense		(4,718	)		(4,266	)
Income taxes		(8,185	)		(3,264	)
		15,239			12,526
Total Income Before Interest Charges		74,825			71,474
INTEREST CHARGES:
Long-term debt		73,383			78,427
Other		5,218			6,166
Allowance for borrowed funds used during construction		(6,002	)		(4,603	)
		72,599			79,990
INCOME (LOSS) FROM CONTINUING OPERATIONS		2,226			(8,516	)
DISCONTINUED OPERATIONS:
Income (Loss) from discontinued operations (net of income taxes(benefits) of $(5) and $3 respectively)		(9	)		5
NET INCOME (LOSS)		2,217			(8,511	)
Preferred stock dividend requirements of subsidiary		975			975
EARNINGS (DEFICIT) APPLICABLE TO COMMON STOCK	$	1,242		$	(9,486	)
Amount per share basic and diluted — (Note 7)
Income / (Loss) from continuing operations	$	0.01		$	(0.07	)
Earnings / (Deficit) applicable to common stock	$	0.01		$	(0.08	)
Weighted Average Shares of Common Stock Outstanding — basic		200,868,612			117,549,912
Weighted Average Shares of Common Stock Outstanding — diluted		201,265,472			117,549,912

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

4

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	2,217		$	(8,511	)
Non-cash items included in net income (loss):
Depreciation and amortization		57,461			52,789
Deferred taxes and deferred investment tax credit		(1,822	)		(4,442	)
AFUDC		(12,134	)		(8,412	)
Amortization of deferred energy costs — electric		32,560			55,854
Amortization of deferred energy costs — gas		3,021			(466	)
Other non-cash		(3,990	)		511
Changes in certain assets and liabilities:
Accounts receivable		29,418			28,357
Deferral of energy costs — electric		(37,085	)		(16,630	)
Deferral of energy costs — gas		1,592			18
Deferral of energy costs — terminated suppliers		2,309			—
Materials, supplies and fuel		(3,018	)		(1,052	)
Other current assets		23,156			22,764
Accounts payable		(56,661	)		16,601
Payment to terminating supplier		(65,368	)		—
Proceeds from claim on terminating supplier		41,365			—
Other current liabilities		4,977			17,214
Discontinued operations — operating activities		14			(8	)
Risk Management assets and liabilites		(12,630	)		(12,380	)
Other assets		4,537			163
Other liabilities		3,278			5,482
Net Cash from Operating Activities		13,197			147,852
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(413,937	)		(165,101	)
AFUDC and other charges to utility plant		12,134			8,412
Customer advances for construction		12,028			5,357
Contributions in aid of construction		7,193			4,032
Net cash used for utility plant		(382,582	)		(147,300	)
Investments in subsidiaries and other property — net		2,838			4,043
Net Cash used by Investing Activities		(379,744	)		(143,257	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		3,612			12,786
Proceeds from issuance of long-term debt		1,030,329			—
Retirement of long-term debt		(600,126	)		(1,167	)
Sale (purchase) of common stock, net of issuance cost		(16	)		1,174
Dividends paid		(968	)		(977	)
Net Cash from Financing Activities		432,831			11,816
Net Increase in Cash and Cash Equivalents		66,284			16,411
Beginning Balance in Cash and Cash Equivalents		172,682			266,328
Ending Balance in Cash and Cash Equivalents	$	238,966		$	282,739
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	75,627		$	64,509
Income taxes	$	3,159		$	—

The accompanying notes are an integral part of the financial statements

5

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)

	March 31,			December 31,
	2006			2005
Common Shareholders’ Equity:
Common stock, $1.00 par value, authorized 250 million; issued and outstanding 2006: 200,792,000 shares; issued and outstanding 2005: 200,792,000 shares	$	200,792		$	200,792
Other paid-in capital		2,220,879			2,220,896
Retained Deficit		(354,642	)		(355,883	)
Accumulated other comprehensive Loss		(5,651	)		(5,651	)
Total Common Shareholders’ Equity		2,061,378			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			50,000
Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% NPC Series Z due 2023		35,000			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			105,000
7.20% NPC Series 1992C due 2022		78,000			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		30,000			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		556,750			744,750
General and Refunding Mortgage Securities
Nevada Power Company
10.88% NPC Series E due 2009		162,500			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			—
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		2,050,000			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)

6

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

	March 31,			December 31,
	2006			2005
Unsecured Debt
Revenue Bonds
Nevada Power Company
5.30% NPC Series 1995D due 2011	$	14,000		$	14,000
5.35% NPC Series 1995E due 2022		13,000			13,000
5.45% NPC Series 1995D due 2023		6,300			6,300
5.50% NPC Series 1995C due 2030		44,000			44,000
5.60% NPC Series 1995A due 2030		76,750			76,750
5.90% NPC Series 1995B due 2030		85,000			85,000
5.80% NPC Series 1997B due 2032		20,000			20,000
5.90% NPC Series 1997A due 2032		52,285			52,285
6.38% NPC Series 1996 due 2036		20,000			20,000
Subtotal		331,335			331,335
Variable Rate Notes
NPC PCRB Series 2000B due 2009		15,000			15,000
NPC IDRB Series 2000A due 2020		100,000			100,000
Subtotal		115,000			115,000
Other Notes
Sierra Pacific Resources
7.803% SPR Senior Notes due 2012		99,142			99,142
8.625% SPR Notes due 2014		335,000			335,000
6.75% SPR Senior Notes due 2017		225,000			225,000
Subtotal, excluding current portion		659,142			659,142
Unamortized bond premium and discount, net		(3,556	)		(3,495	)
Nevada Power Company
8.2% Junior Subordinated Debentures of NPC, due 2037		122,548			122,548
7.75% Junior Subordinated Debentures of NPC, due 2038		72,165			72,165
Subtotal		194,713			194,713
Obligations under capital leases		53,385			56,921
Current maturities and sinking fund requirements		(196,325	)		(58,909	)
Other, excluding current portion		7,136			7,665
Total Long-Term Debt		4,122,580			3,817,122
TOTAL CAPITALIZATION	$	6,233,958		$	5,927,276

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

(Concluded)

7

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)
(Unaudited)

	March 31,		December 31,
	2006		2005
ASSETS
Utility Plant at Original Cost:
Plant in service	$	4,622,317	$	4,106,489
Less accumulated provision for depreciation		1,162,645		1,128,209
		3,459,672		2,978,280
Construction work-in-progress		525,778		698,206
		3,985,450		3,676,486
Investments and other property, net		29,412		29,249
Current Assets:
Cash and cash equivalents		47,577		98,681
Restricted cash		—		52,374
Accounts receivable less allowance for uncollectible accounts: 2006-$30,455; 2005-$30,386		188,762		232,086
Accounts receivable, affiliated companies		18,059		3,738
Deferred energy costs — electric (Note 1)		110,087		186,355
Materials, supplies and fuel, at average cost		51,421		46,835
Risk management assets (Note 5)		28,237		22,404
Intercompany income taxes receivable		48,198		—
Deposits and prepayments for energy		11,802		16,303
Other		14,573		16,075
		518,716		674,851
Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		292,863		214,587
Regulatory tax asset		155,019		155,304
Other regulatory assets		363,521		362,567
Risk management regulatory assets — net (Note 5)		53,707		—
Unamortized debt issuance costs		39,762		37,157
Other		24,939		23,720
		929,811		793,335
TOTAL ASSETS	$	5,463,389	$	5,173,921
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,741,843	$	1,762,089
Long-term debt		2,388,210		2,214,063
		4,130,053		3,976,152
Current Liabilities:
Current maturities of long-term debt		163,925		6,509
Accounts payable		113,942		164,169
Accrued interest		44,482		33,031
Dividends declared		75		397
Accrued salaries and benefits		10,943		15,537
Current income taxes payable		—		3,159
Deferred income taxes		29,260		57,392
Risk management liabilities (Note 5)		61,316		10,125
Accrued taxes		2,667		2,817
Contract termination liabilities		—		89,784
Other current liabilities		48,143		46,425
		474,753		429,345
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		438,087		362,973
Deferred investment tax credit		16,427		16,832
Regulatory tax liability		14,743		15,068
Customer advances for construction		107,299		98,056
Accrued retirement benefits		27,453		24,614
Risk management regulatory liability — net (Note 5)		—		590
Regulatory liabilities		176,400		173,527
Other		78,174		76,764
		858,583		768,424
TOTAL CAPITALIZATION AND LIABILITIES	$	5,463,389	$	5,173,921

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

8

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
OPERATING REVENUES:
Electric	$	381,275		$	354,134
OPERATING EXPENSES:
Operation:
Purchased power		161,596			141,428
Fuel for power generation		89,822			55,640
Deferral of energy costs-net		3,167			35,823
Other		54,133			51,099
Maintenance		14,157			16,955
Depreciation and amortization		34,237			30,402
Taxes:
Income tax benefits		(8,095	)		(6,794	)
Other than income		6,595			6,316
		355,612			330,869
OPERATING INCOME		25,663			23,265
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,429			3,490
Interest accrued on deferred energy		6,783			4,525
Other income		8,397			6,913
Other expense		(1,965	)		(1,576	)
Income taxes		(6,409	)		(3,102	)
		12,235			10,250
Total Income Before Interest Charges		37,898			33,515
INTEREST CHARGES:
Long-term debt		42,739			41,529
Other		3,827			4,332
Allowance for borrowed funds used during construction		(5,372	)		(4,313	)
		41,194			41,548
NET LOSS	$	(3,296	)	$	(8,033	)

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

9

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(3,296	)	$	(8,033	)
Non-cash items included in net loss:
Depreciation and amortization		34,237			30,402
Deferred taxes and deferred investment tax credit		(4,820	)		(3,692	)
AFUDC		(10,801	)		(7,803	)
Amortization of deferred energy costs		21,278			46,673
Other non-cash		(4,436	)		6,020
Changes in certain assets and liabilities:
Accounts receivable		2,611			13,876
Deferral of energy costs		(24,893	)		(10,280	)
Deferral of energy costs — terminated suppliers		1,607			—
Materials, supplies and fuel		(4,586	)		2,905
Other current assets		6,004			7,661
Accounts payable		(46,598	)		15,547
Payment to terminating supplier		(37,410	)		—
Proceeds from claim on terminating supplier		26,391			—
Other current liabilities		8,424			16,976
Risk Management assets and liabilites		(8,939	)		(13,244	)
Other assets		3,572			163
Other liabilities		1,846			(2,052	)
Net Cash from (used by) Operating Activities		(39,809	)		95,119
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(349,409	)		(140,095	)
AFUDC and other charges to utility plant		10,801			7,803
Customer advances for construction		9,242			2,970
Contributions in aid of construction		7,075			(559	)
Net cash used for utility plant		(322,291	)		(129,881	)
Investments in subsidiaries and other property — net		(67	)		1,924
Net Cash used by Investing Activities		(322,358	)		(127,957	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		541,771			—
Retirement of long-term debt		(213,436	)		(2,917	)
Dividends paid		(17,272	)		(19,852	)
Net Cash from (used by) Financing Activities		311,063			(22,769	)
Net Decrease in Cash and Cash Equivalents		(51,104	)		(55,607	)
Beginning Balance in Cash and Cash Equivalents		98,681			243,323
Ending Balance in Cash and Cash Equivalents	$	47,577		$	187,716
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	40,891		$	28,650
Income taxes	$	3,159		$	—

The accompanying notes are an integral part of the financial statements

10

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	March 31,			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		(63,667	)		(43,422	)
Accumulated other comprehensive Loss		(3,339	)		(3,338	)
Total Common Shareholder’s Equity		1,741,843			1,762,089
Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% Series Z due 2023		35,000			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			105,000
7.20% Series 1992C due 2022		78,000			78,000
Subtotal		257,500			257,500
General and Refunding Mortgage Securities
10.88% Series E due 2009		162,500			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			—
Subtotal		1,330,000			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		(4,839	)		(4,942	)
8.2% Junior Subordinated Debentures due 2037		122,548			122,548
7.75% Junior Subordinated Debentures due 2038		72,165			72,165
Subtotal		194,713			194,713
Obligations under capital leases		53,385			56,921
Current maturities and sinking fund requirements		(163,925	)		(6,509	)
Other, excluding current portion		41			45
Total Long-Term Debt		2,388,210			2,214,063
TOTAL CAPITALIZATION	$	4,130,053		$	3,976,152

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

11

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

	March 31,		December 31,
	2006		2005
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,714,510	$	2,695,427
Less accumulated provision for depreciation		1,055,645		1,041,107
		1,658,865		1,654,320
Construction work-in-progress		110,638		66,799
		1,769,503		1,721,119
Investments and other property, net		829		842
Current Assets:
Cash and cash equivalents		152,911		38,153
Restricted cash		—		14,871
Accounts receivable less allowance for uncollectible accounts: 2006-$6,252; 2005-$5,634		152,975		180,973
Accounts receivable, affiliated companies		—		40,278
Deferred energy costs — electric (Note 1)		75,642		67,342
Deferred energy costs — gas (Note 1)		2,052		5,825
Materials, supplies and fuel, at average cost		40,023		41,608
Risk management assets (Note 5)		11,372		27,822
Intercompany income taxes receivable		17,295		—
Deposits and prepayments for energy		11,653		28,751
Other		9,876		9,547
		473,799		455,170
Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		32,633		40,725
Deferred energy costs — gas (Note 1)		5		845
Regulatory tax asset		93,334		93,957
Other regulatory assets		210,538		205,578
Risk management assets (Note 5)		298		—
Risk management regulatory assets — net (Note 5)		35,300		—
Unamortized debt issuance costs		15,372		12,693
Other		15,992		15,372
		403,472		369,170
TOTAL ASSETS	$	2,647,603	$	2,546,301
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	731,438	$	727,777
Preferred stock		50,000		50,000
Long-term debt		1,073,197		941,804
		1,854,635		1,719,581
Current Liabilities:
Current maturities of long-term debt		32,400		52,400
Accounts payable		57,393		56,661
Accounts payable, affiliated companies		15,864		—
Accrued interest		20,028		10,993
Dividends declared		975		968
Accrued salaries and benefits		11,828		14,032
Current income taxes payable		—		49,673
Deferred income taxes		23,245		21,832
Risk management liabilities (Note 5)		36,927		6,455
Accrued taxes		3,227		3,541
Contract termination liabilities		—		39,216
Other current liabilities		10,703		10,299
		212,590		266,070
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		268,143		244,244
Deferred investment tax credit		21,388		21,793
Regulatory tax liability		22,716		23,156
Customer advances for construction		74,791		72,005
Accrued retirement benefits		46,540		41,507
Risk management regulatory liability — net (Note 5)		—		15,015
Regulatory liabilities		113,651		110,911
Other		33,149		32,019
		580,378		560,650
TOTAL CAPITALIZATION AND LIABILITIES	$	2,647,603	$	2,546,301

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

12

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
OPERATING REVENUES:
Electric	$	238,772		$	227,010
Gas		86,725			67,538
		325,497			294,548
OPERATING EXPENSES:
Operation:
Purchased power		92,148			78,724
Fuel for power generation		53,287			54,362
Gas purchased for resale		67,396			53,480
Deferral of energy costs — electric — net		905			4,293
Deferral of energy costs — gas — net		4,731			(328	)
Other		34,175			34,769
Maintenance		7,773			5,991
Depreciation and amortization		23,224			22,387
Taxes:
Income taxes		6,849			6,603
Other than income		5,018			4,748
		295,506			265,029
OPERATING INCOME		29,991			29,519
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		703			319
Interest accrued on deferred energy		1,933			1,583
Other income		2,148			971
Other expense		(2,524	)		(1,640	)
Income tax benefit		(823	)		(452	)
		1,437			781
Total Income Before Interest Charges		31,428			30,300
INTEREST CHARGES:
Long-term debt		17,690			17,307
Other		1,096			1,146
Allowance for borrowed funds used during construction		(630	)		(290	)
		18,156			18,163
NET INCOME		13,272			12,137
Preferred Dividend Requirements		975			975
Earnings applicable to common stock	$	12,297		$	11,162

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

13

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	13,272		$	12,137
Non-cash items included in net loss:
Depreciation and amortization		23,224			22,387
Deferred taxes and deferred investment tax credit		(41,878	)		(2,848	)
AFUDC		(1,333	)		(609	)
Amortization of deferred energy costs — electric		11,282			9,181
Amortization of deferred energy costs — gas		3,021			(466	)
Other non-cash		1,090			(1,641	)
Changes in certain assets and liabilities:
Accounts receivable		53,301			26,595
Deferral of energy costs — electric		(12,192	)		(6,350	)
Deferral of energy costs — gas		1,592			18
Deferral of energy costs — terminated suppliers		702			—
Materials, supplies and fuel		1,584			(3,957	)
Other current assets		16,770			11,472
Accounts payable		13,414			1,026
Payment to terminating supplier		(27,958	)		—
Proceeds from claim on terminating supplier		14,974			—
Other current liabilities		6,921			14,370
Risk Management assets and liabilites		(3,691	)		864
Other assets		965			—
Other liabilities		4,019			5,726
Net Cash from Operating Activities		79,079			87,905
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(64,528	)		(25,006	)
AFUDC and other charges to utility plant		1,333			609
Customer advances for construction		2,786			2,387
Contributions in aid of construction		118			4,591
Net cash used for utility plant		(60,291	)		(17,419	)
Disposal of subsidiaries and other property — net		13			12
Net Cash used by Investing Activities		(60,278	)		(17,407	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		3,612			2,000
Proceeds from issuance of long-term debt		488,557			—
Retirement of long-term debt		(386,608	)		(688	)
Dividends paid		(9,604	)		(975	)
Net Cash from Financing Activities		95,957			337
Net Increase in Cash and Cash Equivalents		114,758			70,835
Beginning Balance in Cash and Cash Equivalents		38,153			19,319
Ending Balance in Cash and Cash Equivalents	$	152,911		$	90,154
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	12,274		$	2,908
Income taxes	$	—		$	—

The accompanying notes are an integral part of the financial statements

14

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands Except Per Share Amounts)

(Unaudited)

	March 31,			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		810,103			810,103
Retained Deficit		(76,877	)		(80,538	)
Accumulated other comprehensive Loss		(1,792	)		(1,792	)
Total Common Shareholder’s Equity		731,438			727,777
Cumulative Preferred Stock:
Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value		50,000			50,000
SPPC Class A Series 1; $1.95 dividend
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		30,000			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		299,250			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		(748	)		(666	)
Current maturities and sinking fund requirements		(32,400	)		(52,400	)
Other, excluding current portion		7,095			7,620
Total Long-Term Debt		1,073,197			941,804
TOTAL CAPITALIZATION	$	1,854,635		$	1,719,581

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

15

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 10-K”).

     The results of operations and cash flows of SPR, NPC and SPPC for the three months ended March 31, 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 (loss) 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 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.

16

     The following deferred energy costs were included in the consolidated balance sheets as of March 31, 2006 (dollars in thousands):

	March 31, 2006
	NPC			SPPC		SPPC		SPR
Description	Electric			Electric		Gas		Total
Unamortized balances approved for collection in current rates
Electric – NPC Period 2 (effective 5/03, 3 years)	$	(2,291	)(1)		—		—	$	(2,291	)
Electric – NPC Period 3 (effective 4/05, 2 years)		38,805			—		—		38,805
Electric – SPPC Period 3 (effective 6/05, 27 months)		—		$	19,205		—		19,205
Electric – NPC Period 4 (effective 4/05, 2 years)		61,063			—		—		61,063
Electric – SPPC Period 4 (effective 6/05, 1 year)		—			3,095		—		3,095
Natural Gas – Period 5 (effective 11/05, 1 year)		—			—	$	1,434		1,434
LPG Gas – Period 3 (effective 11/04, 2 years)		—			—		15		15
LPG Gas – Period 4 (effective 11/05, 1 year)		—			—		124		124
Balances pending PUCN approval		171,447			41,180		—		212,627
Cumulative CPUC balance		—			8,645		—		8,645
Balances accrued since end of periods submitted for PUCN approval		51,540			15,741		484		67,765
Claims for terminated supply contracts(2)		82,386			20,409		—		102,795
Total	$	402,950		$	108,275	$	2,057	$	513,282
Current Assets
Deferred energy costs — electric	$	110,087		$	75,642	$	—	$	185,729
Deferred energy costs — gas		—			—		2,052		2,052
Deferred Assets
Deferred energy costs — electric		292,863			32,633		—		325,496
Deferred energy costs — gas		—			—		5		5
Total	$	402,950		$	108,275	$	2,057	$	513,282

(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.
(2)	Amounts related to claims for terminated supply contracts are discussed in Note 14 of the Notes to Consolidated Financial Statements, Commitments and Contingencies in the 2005 10-K.

Recent Pronouncements

SFAS 123 (R)

     SPR adopted 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 Financial Statements of the Company’s 2005 Annual Report on 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

17

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 March 31, 2006, SPR and the Utilities do not have any financial instruments that meet the criteria specified under SFAS 155.

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

     The net assets and operating results of SPC is reported as discontinued operations in the financial statements for 2006 and 2005. Accordingly, the segment information excludes financial information of SPC.

     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 Financial Statements in the 2005 10-K. Inter-segment revenues are not material (dollars in thousands).

Three Months Ended	NPC		SPPC		Total
March 31, 2006	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	381,275	$	238,772	$	620,047	$	86,725	$	284	$	707,056
Operating Income	$	25,663	$	24,778	$	50,441	$	5,213	$	3,932	$	59,586

Three Months Ended	NPC		SPPC		Total
March 31, 2005	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	354,134	$	227,010	$	581,144	$	67,538	$	292	$	648,974
Operating Income	$	23,265	$	23,864	$	47,129	$	5,655	$	6,164	$	58,948

18

NOTE 3. REGULATORY ACTIONS

Nevada Matters

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 Public Utilities Commission of Nevada (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, sets NPC’s BTER rates such that an estimated $111.7 million of new revenues will be collected for fuel and power purchase in addition to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the $120.1 million increase represents an overall average rate increase of approximately 6.5%.

     NPC’s request for authorization to begin a one year recovery of the $171.5 million of previously incurred purchased fuel and power cost on August 1, 2006 is pending. The requested DEAA adjustment represents an additional rate increase of approximately 9.3%. Intervener testimony addressing the deferred cost balances is due May 26, 2006 and the DEAA hearings are scheduled to begin June 20, 2006 and the PUCN decision is expected before the August 1, 2006 requested implementation date.

Sierra Pacific Power Company

December 2005 Deferred Energy and BTER Update

     On December 1, 2005, SPPC filed an electric DEAA rate case application with the PUCN. The application sought recovery for 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.

     SPPC’s request for authorization to begin a one year recovery of the $46.7 million of previously incurred purchased fuel and power costs on July 1, 2006 is pending. The requested DEAA rate would increase current rates by approximately 6.1%. Intervener testimony addressing the recovery of previously incurred purchased fuel and power costs was filed on May 3, 2006. Hearings are scheduled to begin May 31, 2006 and the PUCN’s decision is expected to be issued in June 2006.

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 26, 2006, the PUCN voted to change electric and gas general rates. The PUCN vote resulted in the following significant items:

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

• Gas general revenue increase: $4.5 million 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 recover SPPC’s allocated amount of the 1999 NPC/SPPC merger costs from Electric customers

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

• New depreciation rates for Gas and Electric facilities

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

California Electric Matters (SPPC)

Sierra Pacific Power Company 2006 Energy Cost Adjustment Clause Rate Case

     On April 3, 2006, SPPC filed with the California Public Utilities Commission (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

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additional $10.1 million. The total request represents an $11.2 million annual revenue increase or a 17.5% average increase to customer rates.

     If approved, SPPC anticipates it will begin recovering these deferred costs in the third 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 June 2006. The earliest rates will become effective is July 1, 2006.

NOTE 4. LONG-TERM DEBT

     As of March 31, 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	$	163,348	(1)	$	31,695		$	—	$	195,043
2007		5,950			2,400			—		8,350
2008		7,066			322,400			—		329,466
2009		184,638			600			—		185,238
2010		282,843			—			—		282,843
		643,845			357,095			—		1,000,940
Thereafter		1,913,129	(2)		749,250			659,142		3,321,521
		2,556,974			1,106,345			659,142		4,322,461
Unamortized Premium(Discount) Amount		(4,839	)		(748	)		2,031		(3,556	)
Total	$	2,552,135		$	1,105,597		$	661,173	$	4,318,905

(1)	NPC’s “2006” amount of $163 million includes $157.5 million of debt that was paid subsequent to March 31, 2006.
(2)	NPC’s “Thereafter” amount of $1.9 billion includes $105 million of debt that was paid subsequent to March 31, 2006. However, due to a conditional notice of redemption, such amount remained in “Thereafter”.

     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)

Redemption Notice

     On April 28, 2006, NPC provided a notice of redemption to holders of the Company’s 7.20% Clark County Industrial Development Revenue Bonds, due October 1, 2022, in the amount of $78 million. The bonds will be redeemed on May 30, 2006 at 100% of the stated principal amount, plus interest accrued to the date of redemption.

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 NPC’s revolving credit facility, which was borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Power Plant.

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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.

Revolving Credit Facility

     On April 19, 2006, NPC increased the size of its second amended and restated revolving credit facility to $600 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of March 31, 2006, NPC had $55.2 million of letters of credit and had borrowed $275 million under the revolving credit facility. As of April 28, 2006, NPC had $55.2 million of letters of credit and had borrowed $300 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 March 31, 2006, NPC was in compliance with these covenants.

     The NPC Credit Agreement provides 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.

     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 2005 Form 10-K.

Financing Transactions (SPPC)

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 to redeem the following:

• 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 $20 million aggregate principal amount of SPPC Collateralized Medium Term 6.81% to 6.83% Series C Notes due 2006,

     The remaining proceeds of $112 million will be used as follows:

• payment of approximately $51 million in connection with the redemption of SPPC’s Series A Preferred Stock on June 1, 2006. The stock will be redeemed at a redemption price per share of $25.683, plus accrued dividends to the redemption date of $.4875 per share. As of March 31, 2006, there were 2 million shares outstanding;

• payment for maturing debt of $10 million aggregate principal amount of SPPC Collateralized Medium Term 6.81% Series C Notes due April 2006;

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

• payment of related fees and for general corporate purposes.

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Revolving Credit Facility

     On April 19, 2006, SPPC increased the size of its amended and restated revolving credit facility to $350 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of March 31, 2006, SPPC had $10.8 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility. As of April 28, 2006, SPPC had $12.6 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 March 31, 2006, SPPC was in compliance with these covenants.

     The SPPC Credit Agreement provides 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.

     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 10, Debt Covenant Restrictions.

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):

	March 31,						December 31,
	2006						2005
	SPR		NPC		SPPC		SPR			NPC			SPPC
Risk management assets	$	39.9	$	28.2	$	11.7	$	50.2		$	22.4		$	27.8
Risk management liabilities	$	98.2	$	61.3	$	36.9	$	16.6		$	10.1		$	6.5
Risk management regulatory assets (liabilities)	$	89.0	$	53.7	$	35.3	$	(15.6	)	$	(.6	)	$	(15.0	)

     The decrease in net risk management assets as of March 31, 2006 as compared to December 31, 2005 is due to unfavorable positions on natural gas options held by the Utilities as a result of decreasing prices.

     Also included in risk management assets were $30.7 million, $20.7 million, and $10.0 million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at March 31, 2006.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Mohave Generation Station

     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,

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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. The estimated cost of new pollution controls to meet the limits, and other capital investments is $1.2 billion. Should such investments be undertaken in the future, as a 14% owner in Mohave, NPC’s cost would be $168 million.

     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.

     Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE’s share of Mohave. On October 20, 2004, the CPUC issued a proposed decision which, among other things, directed SCE to continue negotiations with the Tribes regarding post-2005 coal and water supply, and directed SCE to conduct a study of potential alternatives to Mohave.

     Because coal and water supplies necessary for long-term operation of Mohave have yet to be secured, SCE and the other Mohave co-owners (the “Owners”) have been prevented from commencing the installation of extensive pollution control equipment that must be put in place to meet the emission limits contained in the decree. 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 installation of required pollution control equipment. Thus, the Owners suspended operation of the plant on December 31, 2005, pending resolution of these issues. It is the Owners’ intent to preserve their ability to restart the plant at a later date should these issues be resolved, and economic analysis at that time support such a decision. NPC’s ownership interest in Mohave comprised approximately 10% of NPC’s peak generation capacity.

     The co-tenancy agreement and the operating agreement between the Owners expires on July 1, 2006. The Owners have been 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 if they do not choose to continue to participate in future operations.

     See further discussion of Mohave under Regulatory Contingencies.

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 to satisfy the NDEP order expended to date are approximately $26.7 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.

     NPC is engaged in an ongoing dialogue and settlement discussions with NDEP and the EPA and DOJ regarding the NOAVs. Management has booked a minimum liability with respect to these matters; however, because management cannot predict at this time whether a final settlement will be reached, it cannot accurately predict the cost of 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. Any environmental controls and equipment changes needed to assure compliance with existing or modified regulations will be submitted by NPC to the PUCN for approval.

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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 Department of Justice, 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 unable to predict the outcome of this action.

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

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. Both motions are pending and the parties are conducting limited discovery in Federal court in connection with the motions. NPC is unable to predict the outcome of the decision.

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

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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.

     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 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 a new (partial) summary judgment motion with respect to coverage, which the court also denied. Parties are awaiting a trial date.

     The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. 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 the cost to rebuild the dam as it believes its overall exposure is insignificant.

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 Piñon Pine unit. 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.

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

     NPC’s ownership interest in Mohave comprises approximately 10% of NPC’s peak generation capacity. SCE is the operating partner of Mohave.

     Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Tribes. This coal is 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. Due to the uncertainty over a post-2005 coal supply, the Owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave’s operations are extended past 2005. See the Environmental section above for further discussion on Mohave’s environmental issue. As such, on December 31, 2005 the Owners of the Mohave plant suspended operation, pending resolution of these issues.

     NPC’s Integrated Resource Plan (IRP) accepted by the PUCN in November 2003, assumes the Plant will be unavailable after December 31, 2005. In addition, in its General Rate Case filed on October 1, 2003, NPC requested that the PUCN authorize a higher depreciation rate be applied to Mohave in order to recover the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN. While the PUCN did not approve higher depreciation rates, they did authorize 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. Approximately $27.2 million was reclassified from Plant in Service to Other Regulatory assets on December 31, 2005. 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.

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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 net losses for the three months ended March 31, 2005 these items are anti-dilutive. Accordingly, diluted EPS for this period are computed using the weighted average shares outstanding before dilution.

     For the three months ended March 31, 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 2005 10-K Note 7, Long-Term Debt, 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 net losses for the three months ended March 31, 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 March 31,
	2006			2005
Basic EPS
Numerator ($000)
Income/(Loss) from continuing operations	$	2,226		$	(8,516	)
Income/(Loss) from discontinued operations	$	(9	)	$	5
Earnings/(Deficit) applicable to common stock	$	1,242		$	(9,486	)
Denominator
Weighted average number of common shares outstanding		200,868,612			117,549,912
Per Share Amounts
Income/(Loss) from continuing operations	$	0.01		$	(0.07	)
Income/(Loss) from discontinued operations	$	—		$	—
Earnings/(Deficit) applicable to common stock	$	0.01		$	(0.08	)
Diluted EPS
Numerator ($000)
Income/(Loss) from continuing operations	$	2,226		$	(8,516	)
Income/(Loss) from discontinued operations	$	(9	)	$	5
Earnings/(Deficit) applicable to common stock	$	1,242		$	(9,486	)
Denominator(1)
Weighted average number of shares outstanding before dilution		200,868,612			117,549,912
Stock options		73,905			—
Executive long term incentive plan — restricted		112,074			—
Non-Employee Director stock plan		25,287			—
Employee stock purchase plan		2,168			—
Performance Shares		183,426			—
		201,265,472			117,549,912
Earnings (Deficit) Per Share Amounts
Income from continuing operations	$	0.01		$	(0.07	)
Loss from discontinued operations	$	—		$	—
Earnings applicable to common stock	$	0.01		$	(0.08	)

(1) The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the three months ended March 31, 2006 and 2005, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the three months ended March 31, 2006 and 2005, 919,914 and 1.1 million shares, respectively, would be included. The denominator does not include stock equivalents resulting from the conversion of the Corporate PIES, for the three months ended March 31, 2005. The amounts that would have been included in the calculation, if the conversion price were met would have been 17.3 million shares.

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NOTE 8. GOODWILL AND OTHER MERGER COSTS

     SPR’s Consolidated Balance Sheet as of March 31, 2006 included approximately $4 million of goodwill assigned to SPR’s unregulated operations and approximately $19 million of goodwill assigned to SPPC’s regulated gas business. The goodwill assigned to the regulated gas business is subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulations”, which permits SPPC to capitalize certain costs that may be recovered through rates. On April 26, 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 $19 million will be reclassified as a regulatory asset and then 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.

NOTE 9. PENSION AND OTHER POST-RETIREMENT BENEFITS

     A summary of the components of net periodic pension and other postretirement costs for the three months ended March 31 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	$	5,758		$	4,620		$	883		$	820
Interest cost		9,157			8,062			2,571			2,465
Expected return on plan assets		(10,182	)		(9,042	)		(1,230	)		(966	)
Amortization of prior service cost		473			428			31			16
Amortization of Transition Obligation		—			—			242			242
Amortization of net (gain)/loss		2,443			1,614			1,154			946
Special Termination Charges		—			181			—			3
Net periodic benefit cost	$	7,649		$	5,863		$	3,651		$	3,526

     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 Annual Report on 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

     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 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 Financial Statements.

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     As of March 31, 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.      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. As of May 2, 2006, SPR had 200,879,752 shares of common stock outstanding.

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

Forward-Looking Statements and Risk Factors

     The information in thisForm 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)	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;
(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)	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 Public Utilities Commission of Nevada (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;
(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 recorded by SPPC for its gas distribution business;
(5)	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;
(6)	whether NPC will be successful in obtaining 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;
(7)	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, limitations imposed by the Federal Power Act, and in the case of SPPC, under the terms of SPPC’s restated articles of incorporation;
(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 final outcome of NPC’s pending lawsuit in Nevada state court seeking to reverse portions of the PUCN’s 2002 order denying the recovery of NPC’s deferred energy costs;
(10)	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;

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(11)	industrial, commercial, and residential growth in the service territories of the Utilities;
(12)	employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages;
(13)	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;
(14)	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;
(15)	the financial decline of any significant customers;
(16)	changes in environmental laws or regulations, including the imposition of significant new limits on mercury and other emissions from coal-fired power plants;
(17)	changes in tax or accounting matters or other laws and regulations to which SPR or the Utilities are subject;
(18)	future economic conditions, including inflation rates and monetary policy;
(19)	financial market conditions, including changes in availability of capital or interest rate fluctuations; and
(20)	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

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

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EXECUTIVE OVERVIEW

     Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations 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.

     During the first quarter of 2006, NPC’s revenues increased from the same period in 2005 primarily as a result of higher rates that went into effect in October 2005 and customer growth. On April 12, 2006, the PUCN approved an overall increase of NPC’s Base Tariff Energy Rates (BTER) effective May 1, 2006. The increase combined with a previously approved Deferred Energy Accounting Adjustment (DEAA) rate case represents an approximate 6.5% average rate increase. NPC’s 2006 first quarter net loss was less than the first quarter of 2005 primarily due to increased revenues, allowance for other funds used during construction, interest accrued on deferred energy and the carrying charge allowed for the newly completed Lenzie generating station.

     SPPC electric and gas revenues increased primarily as a result of higher rates and 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 below underRegulatory Proceedings. On April 12, 2006 the PUCN approved an overall 3.5% increase in BTER. Additionally, on April 26, 2006 the PUCN voted for a general electric revenue decrease of approximately $14 million and a general gas revenue increase of approximately $4.5 million to begin on May 1, 2006.

     SPR recognized net income of $2.2 million for the three months ended March 31, 2006, compared to a net loss of $8.5 million for the same period in 2005. The improvement in earnings is primarily attributable to a decrease in interest charges due to refinancing activities, increased Allowance for Other Funds used During Construction and Allowance for Borrowed Funds used During Construction. In addition, increased interest on deferred energy and the carrying charge associated with the Lenzie Generating Station increased earnings.

Business Issues

     SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core business. 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. NPC and SPPC will continue to be subject to markets, that over recent years have been volatile, for energy necessary to serve the Utilities’ customers that are in excess of owned generation, as well as, natural gas. Growth in Las Vegas shows no signs of slowing. Construction is expected to begin later this year on Project City Center, a $7 billion development on the Las Vegas Strip consisting of hotel-casino space, condominiums, retail and restaurants. We estimate that Project City Center could require up to 120 megawatts (MWs) of electricity once it is fully developed. In addition, other developers are planning multi-billion projects that, collectively, are as large as City Center. 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 continued to make progress toward this goal during the first quarter of this year.

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. The Utilities’ significant need to tap energy markets is due to the fact that the Utilities’ ownership and contractual call on power generating assets is insufficient to meet our customers’ energy

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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 encompasses 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.

Generation Strategy

     In 2003, NPC and SPPC embarked on a strategy to build electric power plants to reduce their exposure to the energy markets, reduce the overall price and volatility for its customers, and to increase the earnings of SPR. 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 designation 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% enhanced ROE if the two Lenzie generator units are 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 1% enhancement. NPC believes it is eligible to receive the 3% enhancement, as discussed above, to the otherwise authorized ROE that will be decided as a result of its General Rate Case (GRC) filing to be made in November 2006.

     On June 21, 2005, NPC announced that it signed an agreement to acquire from Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy Corporation (PWEC), a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC (“GenWest”), a 75 percent ownership interest in the Silverhawk Power Plant (“Silverhawk”). Silverhawk is a 560-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles northeast of Las Vegas. In January 2006, NPC completed the $208 million purchase of Silverhawk.

     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 by June 2008. The unit will provide needed generation within SPPC’s control area to reliably serve the growing needs of Northern Nevada.

     In January 2006, the Utilities announced their intention 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, as well as 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 to follow within three years thereafter. The total estimated capital expenditures associated with the two coal plants and the transmission line is approximately $3 billion.

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 for 2006. 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 issue new debt as necessary. If energy costs continue to 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.

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     So far in 2006, the Utilities have completed major financing transactions that lower our interest costs, improve liquidity and extend maturities. The following lists those completed as of the end of the first quarter of 2006:

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

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

• Early redemption of $110 million of SPPC’s Collateralized Medium Term 6.95% to 8.61% Series A Notes due 2022

• Early redemption of $58 million of SPPC’s Collateralized Medium Term 7.10% to 7.14% Series B Notes due 2023

• Payment for maturing debt of $20 million for SPPC’s Collateralized Medium Term 6.81% Series C Notes

     Major financing transactions completed subsequent to the first quarter of 2006 include, but are not limited to:

• Issuance of $250 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036

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

• Payment of $10 million for SPPC’s Collateralized Medium Term 6.81% that matured in April 2006

• Redemptions of various NPC debt of approximately $262.5 million, including $35 million 8.5% First Mortgage Bonds, Series Z, due 2023; $105 million 6.7% Clark County, Nevada, Industrial Development Revenue Bonds, due 2022; and $122.5 million 8.2% Junior Subordinated Deferrable Interest Debentures

     Additionally, NPC announced a notice of redemption for holders of its 7.2% Clark County Industrial Development Revenue bonds in the amount of $78 million which will be redeemed on May 30, 2006. SPPC announced a notice of redemption for holders of its Class A Preferred Stock, Series 1. The stock will be redeemed on June 1, 2006.

 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 its 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 our regulators for the benefit of all stakeholders. Details regarding recently approved and pending rate cases are discussed below inRegulatory Proceedingsand in our 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 $13.0 million and $19.6 million of interest costs for the three months ended March 31, 2006 and 2005, respectively.

     During the three months ended March 31, 2006, SPR recognized earnings applicable to common stock of approximately $1.2 million compared to an approximate $9.5 million deficit applicable to common stock for the same period in 2005. The change in SPR’s consolidated earnings during the three months ended March 31, 2006 compared to the same period in 2005 was primarily due to a decrease in interest expense due to refinancing activities, increased Allowance for Other Funds used During Construction and Allowance for Borrowed Funds use During Construction. In addition, increased interest on deferred energy improved earnings.

     As of March 31, 2006, NPC had paid $17.3 million in dividends to SPR and SPPC had paid $8.6 million in dividends to SPR. On May 2, 2006, NPC and SPPC declared a $14.7 million and $7.3 million dividend, respectively, payable to SPR. SPPC paid $975 thousand in dividends to holders of its preferred stock in the quarter ended March 31, 2006 and declared for the second quarter $975 thousand in dividends to holders of its preferred stock.

ANALYSIS OF CASH FLOWS

     SPR’s consolidated net cash flows increased for the three months ended March 31, 2006 compared to the same period in 2005, primarily as a result of an increase in cash from financing activities offset by an increase in cash used in investing activities and a decrease in cash from operating activities.

     During the first quarter of 2006, NPC borrowed approximately $335 million under its revolving credit facility of which approximately $210 million was repaid from the proceeds of the issuance of $210 million of NPC’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016. Additionally, SPPC borrowed approximately $198 million under its revolving credit facility to retire approximately $188 million of SPPC’s Medium Term Series A, B and C Notes. Additionally, SPPC issued $300 million 6.0% General and Refunding Mortgage Notes, Series M to pay the $198 million borrowed under the revolving credit facility. SPPC intends to use a portion of the remaining proceeds to pay for future redemptions and payments of maturing debt of approximately $81 million.

     Cash used by investing activities increased significantly when compared with the same period in 2005 primarily due to construction at NPC for the Lenzie Generating Station and NPC’s purchase of Silverhawk. Additionally, SPPC’s expansion of the Tracy Generating Station contributed to the increase in cash used by investing activities.

     Cash from operating activities decreased compared to the same period in 2005. The decrease is primarily due to a change in NPC’s purchase power transactions, the Utilities’ settlement of Enron, and for NPC a decrease in collection for deferred energy balances. In the first quarter of 2005, NPC payments to purchase power suppliers were offset by additional amounts owed to suppliers at March 31, 2005. In contrast, in the first quarter of 2006, NPC paid purchase power obligations existing at December 31, 2005, which were not offset by obligations due to the reduction in purchase power transactions as a result of the addition of Silverhawk and Lenzie Generating Stations.

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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 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 $37.7 million at March 31, 2006. SPR has approximately $51.8 million payable of debt service obligations for 2006, which it intends to pay through dividends from subsidiaries. See Dividends from Subsidiaries below.

     SPR paid approximately $22 million of debt service obligations on its existing debt securities during the first quarter of 2006. SPR has approximately $29.8 million payable of debt service obligations remaining during 2006, which SPR expects to meet through the payment of dividends by the Utilities to SPR.

     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. However, to fund capital requirements, as discussed in the 2005 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.

     During the three months ended March 31, 2006, there were no material changes to contractual obligations as set forth in SPR’s 2005 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 March 31, 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 8⁵/₈% 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, guarantee holders, NPC’s preferred trust security holders, and SPPC’s preferred stockholders.

     As of March 31, 2006, SPR, NPC, SPPC, and their subsidiaries had approximately $4.3 billion of debt and other obligations outstanding, consisting of approximately $2.5 billion of debt at NPC, approximately $1.1 billion of debt at SPPC and approximately $0.7 billion of debt at the holding company and other subsidiaries. Additionally, SPPC had $50 million of outstanding preferred stock. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, 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 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

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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 Financial Statements.

     As of March 31, 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 March 31, 2006, NPC had paid $17.3 million in dividends to SPR and SPPC had paid $8.6 million in dividends to SPR. On May 2, 2006, NPC and SPPC declared a $14.7 million and $7.3 million dividend, respectively, payable to SPR.

Limitations on Indebtedness

     The terms of SPR’s $335 million 8 5/8% 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 March 31, 2006, SPR, NPC and SPPC would have been able to issue approximately $262 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.00%, 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 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 10-K.

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. As of May 2, 2006, SPR had 200,879,752 shares of common stock outstanding.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

     During the three months ended March 31, 2006, NPC incurred a net loss of approximately $3.3 million compared to a net loss of approximately $8.0 million for the same period in 2005. NPC paid a common stock dividend of $17.3 million to SPR in the three months ended March 31, 2006 and declared a dividend of approximately $14.7 million on May 2, 2006.

     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.

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

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Operating Revenues:
Electric	$	381,275	$	354,134		7.7	%
Energy Costs:
Purchased power		161,596		141,428		14.3	%
Fuel for power generation		89,822		55,640		61.4	%
Deferral of energy costs-electric-net		3,167		35,823		-91.2	%
		254,585		232,891		9.3	%
Gross Margin	$	126,690	$	121,243		4.5	%

     The causes for significant changes in specific lines comprising the results of operations for NPC are discussed below (in $000’s):

	Three Months
	Ended March 31,				Change from
	2006		2005		Prior Year %
Electric Operating Revenues ($000):
Residential	$	157,895	$	143,005		10.4	%
Commercial		87,936		82,755		6.3	%
Industrial		113,955		103,332		10.3	%
Retail revenues		359,786		329,092		9.3	%
Other		21,489		25,042		-14.2	%
Total Revenues	$	381,275	$	354,134		7.7	%
Retail sales in thousands of megawatt-hours (MWH)		4,002		3,788		5.6	%
Average retail revenue per MWH	$	89.90	$	86.88		3.5	%

     NPC’s retail revenues increased for the three months ended March 31, 2006 as compared to the same period in the prior year due to increases in rates and customer growth. The increase in rates became effective October 1, 2005, as a result of an update to NPC’s BTER. Growth in residential, commercial and industrial customers (5.0%, 4.9% and 1.6%, respectively) also contributed to the increase. These increases were slightly offset by a decrease resulting from NPC’s 2004 Deferred Energy Rate Case effective April 1, 2005. Based on NPC’s customer forecast, NPC expects retail electric customers in its service territory to continue to grow through the year. On January 17, 2006, NPC filed an application to establish a new deferred energy rate and to increase it’s going forward BTER to reflect future energy costs. On April 12, the PUCN approved an overall increase of 5.7% in BTER rates effective May 1, 2006, and scheduled hearings to review the deferred energy rate increase request for June 2006 (refer to Regulatory Proceedings, later).

     The decrease in Electric Operating Revenues-Other for the three month period ended March 31, 2006 compared to the same period in 2005 was primarily due to certain transactions that were reported in revenues for the three months ended March 31, 2005, which are now being netted in purchase power. Other decreases include lower revenues from wheeling sales and transmission ancillary services as well as decreases in energy usage by public authority customers due to their transitioning to distribution-only services. Partially offsetting these decreases was an increase in revenues from economy energy sales to the Colorado River Commission.

Purchased Power

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Purchased Power	$	161,596	$	141,428		14.3	%
Purchased Power in thousands of MWhs		2,300		2,240		2.7	%
Average cost per MWh of Purchased Power	$	70.26	$	63.14		11.3	%

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     NPC’s purchased power costs were higher for the three months ended March 31, 2006 compared to the same period in 2005 due to higher prices and increased volume. Volume increases reflect growth in customer demand. Partially offsetting the 2006 purchased power costs and volumes are certain transactions that were reported in revenues for the first quarter of 2005 which are now netted against purchased power.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Fuel for Power Generation	$	89,822	$	55,640		61.4	%
Thousands of MWhs generated		1,929		1,886		2.3	%
Average cost per MWh of Generated Power	$	46.56	$	29.50		57.8	%

     Fuel for power generation increased in the three months ended March 31, 2006 compared to the same period in 2005 due primarily to higher natural gas prices, the shutdown of the Mohave Coal Generating Station (“Mohave”) and the replacement of Mohave generation by the Silverhawk and Lenzie natural gas generating stations beginning in January 2006 and February 2006, respectively. Silverhawk and Lenzie are highly efficient generating stations which require less natural gas to produce energy; however, the cost of coal is substantially lower than the cost of natural gas. In the first quarter of 2005, Mohave generation represented approximately 21% of total generation.

Deferred Energy Costs — Net

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Deferred energy costs — net	$	3,167	$	35,823		-91.2	%
Total	$	3,167	$	35,823		-91.2	%

     Deferral 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 for 2006 and 2005 include amortization of deferred energy costs of $21.3 million and $46.7 million, respectively; and under-collections of amounts recoverable in rates of $18.1 million and $10.9 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Allowance for other funds used during construction	$	5,429	$	3,490		55.6	%
Allowance for borrowed funds used during construction	$	5,372	$	4,313		24.6	%
	$	10,801	$	7,803		38.4	%

     AFUDC for NPC is higher for the three months ended March 31, 2006 compared to the same period in 2005 due to an increase in Construction Work in Progress (CWIP). The increase is primarily due to the purchase of the partially completed

37

Lenzie Generating Station in October 2004 and the subsequent construction costs to complete the plant. Block 1 and 2 of the Lenzie Generating Station were completed and placed into service in January and April 2006, respectively.

Other (Income) and Expenses

	Three Months Ended March 31,
							Change from
	2006			2005			Prior Year %
Other operating expense	$	54,133		$	51,099			5.9	%
Maintenance expense	$	14,157		$	16,955			-16.5	%
Depreciation and amortization	$	34,237		$	30,402			12.6	%
Interest charges on long-term debt	$	42,739		$	41,529			2.9	%
Interest charges-other	$	3,827		$	4,332			-11.7	%
Interest accrued on deferred energy	$	(6,783	)	$	(4,525	)		49.9	%
Other income	$	(8,397	)	$	(6,913	)		-21.5	%
Other expense	$	1,965		$	1,576			24.7	%

     Other operating expense increased slightly for the three months ended March 31, 2006 compared to the same period in 2005 primarily due to an increase in software licensing fees and financing related activities. Partially offsetting these items was a decrease in legal fees and costs incurred for the reorganization of NPC, SPPC and SPR in 2005.

     Maintenance expense decreased for the three months ended March 31, 2006 compared to the same period in 2005 due to outages scheduled at Navajo during the first quarter of 2005 and the shut-down of the Mohave generating station partially offset by scheduled and forced outages at Clark Station and the addition of Lenzie and Silverhawk Generating Stations in 2006.

     Depreciation and amortization expenses were higher during the three months ended March 31, 2006 compared to the same period in 2005 primarily as a result of increases to plant-in-service. The increase is primarily due to the acquisition of Silverhawk, which was placed in service in January of 2006.

     Interest charges on Long-Term Debt increased for the three months ended March 31, 2006, compared to the same period in 2005 due primarily to increases in long-term debt balances related to new debt issued in January 2006 of $210 million and interest associated with various draws from the Long-Term Credit Facility, partially offset by debt redemptions in July 2005 of $210 million. See Note 7, Long-Term Debt of the Notes to Financial Statements in the 2005 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt of the Notes to Financial Statements in this 10-Q.

     Interest charges-other for the three months ended March 31, 2006 decreased compared to the same period in 2005 due to settlements in 2005 with terminated energy suppliers which reduced associated interest costs on the terminated supplier balances, offset partially by higher amortization costs for the early redemption of NPC’s Series E and G General Refunding Mortgage Notes.

     NPC’s interest accrued on deferred energy costs increased for the three months ended March 31, 2006 due to higher deferred energy balances compared to the same period in 2005. See Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements for further details of deferred energy balances.

     Other income increased during the three months ended March 31, 2006 compared to the same period in 2005 due to income related to the recently completed Lenzie plant, partially offset by lower amortization of gains associated with disposition of SO2 allowances and expiration of the amortization period on sale of property.

     Other expense increased during the three months ended March 31, 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 improved slightly during the three months ended March 31, 2006, compared to the same period in 2005 resulting primarily from an increase in cash from financing activities offset by an increase in cash used for investing activities and operating activities.

     During the first quarter of 2006, NPC borrowed approximately $335 million under its revolving credit facility of which approximately $210 million was repaid from the proceeds of the issuance of $210 million of NPC’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016. Additionally, NPC paid dividends to SPR of approximately $17.3 million.

     Cash used by investing activities increased significantly when compared with the same period in 2005 primarily due to construction at NPC for the Lenzie Generating Station and NPC’s purchase of Silverhawk.

     Cash used by operating activities increased compared to the same period in 2005. The increase is primarily due to a change in purchase power transactions, the settlement of Enron, and a decrease in collection for deferred energy balances. In the first quarter of 2005, NPC payments to purchase power suppliers were offset by additional amounts owed to suppliers at March 31, 2005. In contrast, in the first quarter of 2006, NPC paid purchase power obligations existing at December 31, 2005, which were not offset by obligations due to the reduction in purchase power transactions as a result of the addition of Silverhawk and Lenzie Generating Stations.

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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, natural gas, other operating expenses and interest. NPC had cash and cash equivalents of approximately $47.6 million at March 31, 2006. As of April 28, 2006, NPC had $244.8 million available under its existing revolving credit facility as discussed below in financing transactions.

     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. However, to fund capital requirements, as discussed below, NPC may 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.

     During the three months ended March 31, 2006, there were no material changes to contractual obligations as set forth in NPC’s 2005 Form 10-K except for certain financing transactions as discussed below.

Financing Transactions

 Redemption Notice

     On April 28, 2006, NPC provided a notice of redemption to holders of the Company’s 7.20% Clark County Industrial Development Revenue Bonds, due October 1, 2022, in the amount of $78 million. The bonds will be redeemed on May 30, 2006 at 100% of the stated principal amount, plus interest accrued to the date of redemption.

 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 NPC’s revolving credit facility, which was borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Power Plant.

 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 as follows:

• 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.

 Revolving Credit Facility

     On April 19, 2006, NPC increased the size of its second amended and restated revolving credit facility to $600 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of March 31, 2006, NPC had $55.2 million of letters of credit and had borrowed $275 million under the revolving credit facility. As of April 28, 2006, NPC had $55.2 million of letters of credit and had borrowed $300 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 March 31, 2006, NPC was in compliance with these covenants.

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     The NPC Credit Agreement provides 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.

     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 2005 Form 10-K.

Factors Affecting Liquidity

Limitations on Indebtedness

     The terms of NPC’s Series E Notes, which mature in 2009, 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 E Notes, 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.

Mortgage Indentures

     NPC’s Indenture of Mortgage, dated as of October 1, 1953, between NPC and Deutsche Bank Trust Company Americas (the “First Mortgage Indenture”), creates a first priority lien on substantially all of NPC’s properties. As of March 31, 2006, $372.5 million of NPC’s first mortgage bonds were outstanding. In connection with the issuance of its Series E, Series G and Series I Notes, NPC agreed that it would not issue any more first mortgage bonds. As of April 28, 2006, $232.5 million of NPC’s first mortgage bonds were outstanding.

     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 March 31, 2006, $1.8 billion of NPC’s General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

1.	70% of net utility property additions,
2.	the principal amount of retired General and Refunding Mortgage Bonds, and/or
3.	the principal amount of first mortgage bonds retired after October 19, 2001.

     On the basis of (1), (2) and (3) above and on plant accounting records as of March 31, 2006, NPC had the capacity to issue approximately $785 million of additional General and Refunding Mortgage securities. This amount does not reflect the issuance in April 2006 of $250 million Series N General and Refunding Mortgage notes, and $100 million of G&R bonds issued to secure the increased revolving credit facility.

     Although NPC has substantial capacity to issue additional General and Refunding Mortgage securities on the basis of property additions and retired securities, the financial covenants contained in the Series E, Series G, Series I, and Series L Notes, the Revolving Credit Facility limits the amount of additional indebtedness that NPC may issue and the reasons for which such indebtedness may be issued.

     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 other indebtedness) 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.

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SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

     During the three months ended March 31, 2006, SPPC recognized net income of approximately $13.3 million compared to $12.1 million for the same period in 2005. SPPC paid a common stock dividend of $8.6 million to SPR in the three months ended March 31, 2006 and declared a dividend of approximately $7.3 million on May 2, 2006. Additionally, SPPC paid $975 thousand in dividends in the first quarter of 2006 and declared an additional $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.

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

	Three Months Ended March 31,
						Change from
	2006		2005			Prior Year %
Operating Revenues:
Electric	$	238,772	$	227,010			5.2	%
Gas		86,725		67,538			28.4	%
	$	325,497	$	294,548			10.5	%
Energy Costs:
Purchased Power	$	92,148	$	78,724			17.1	%
Fuel for power generation		53,287		54,362			-2.0	%
Deferral of energy costs-electric-net		905		4,293			-78.9	%
Gas purchased for resale		67,396		53,480			26.0	%
Deferral of energy costs-gas-net		4,731		(328	)		N/A
	$	218,467	$	190,531			14.7	%
Energy Costs by Segment:
Electric	$	146,340	$	137,379			6.5	%
Gas		72,127		53,152			35.7	%
	$	218,467	$	190,531			14.7	%
Gross Margin by Segment:
Electric	$	92,432	$	89,631			3.1	%
Gas		14,598		14,386			1.5	%
	$	107,030	$	104,017			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 Ended March 31,
					Change from Prior
	2006		2005		year %
Electric Operating Revenues:
Residential	$	82,363	$	73,572		11.9	%
Commercial		81,834		72,543		12.8	%
Industrial		66,360		73,335		-9.5	%
Retail		230,557		219,450		5.1	%
Other1		8,215		7,560		8.7	%
Total Revenues	$	238,772	$	227,010		5.2	%
Retail sales in thousands of MWh		2,069		2,296		-9.9	%
Average retail revenue per MWh	$	111.43	$	95.58		16.6	%

¹ Primarily wholesale, as discussed below.

     SPPC’s retail revenues increased for the three months ended March 31, 2006 as compared to the same period in the prior year due to increases in retail rates and customer growth. Retail rates increased due to various Deferred Energy and BTER cases in the Nevada jurisdiction and increased rates in SPPC’s California jurisdiction effective September 1, 2005. Growth in residential and commercial customers (2.7%, and 2.2%, respectively) also contributed to the increase in revenues. 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 April 26, 2006, the PUCN voted for a general electric revenue decrease of approximately 1.5%, effective May 1, 2006. In December 2005, SPPC filed an application to

42

establish a new deferred energy rate and to reset its BTER. On April 12, 2006, the PUCN approved an overall 3.5% increase in BTER rates and scheduled hearings to review the deferred energy rate increase request for May 2006 (refer to Regulatory Proceedings, later).

     The increase in Electric Operating Revenues-Other for the three month period ended March 31, 2006 compared to the same period 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 Ended March 31,
					Change from
	2006		2005		Prior year %
Gas Operating Revenues:
Residential	$	49,289	$	37,519		31.4	%
Commercial		22,743		18,619		22.1	%
Industrial		7,751		5,723		35.4	%
Retail revenue		79,783		61,861		29.0	%
Wholesale revenue		6,149		5,020		22.5	%
Miscellaneous		793		657		20.7	%
Total Revenues	$	86,725	$	67,538		28.4	%
Retail sales in thousands of decatherms		6,340		6,399		-0.9	%
Average retail revenues per decatherm	$	12.58	$	9.67		30.1	%

     SPPC’s retail gas revenues increased for the three months ended March 31, 2006, primarily due to increases in retail rates and customer growth. Retail rates increased as a result of SPPC’s Purchased Gas Adjustment filing effective August 1, 2005 and SPPC’s Gas Deferred Energy Rate Case and BTER Update effective November 1, 2005. Growth in residential, commercial and industrial customers (4.2%, 3.2% and 23.7%, respectively) also contributed to the increase in revenues. This was partially offset by warmer temperatures in the first quarter of 2006 as compared to the same period of 2005. In October 2005, SPPC filed a Gas GRC requesting an overall increase of 5.4%. On April 26, 2006, the PUCN voted for a general revenue increase of approximately 2.3%, effective May 1, 2006 (refer to Regulatory Proceedings, later).

     Wholesale gas revenues for the three months ended March 31, 2006 increased from the same period in 2005 due to warmer temperatures during the first quarter of 2006 which increased the availability of gas for wholesale sales.

     Miscellaneous revenues for the three months ended March 31, 2006 increased from the same period in 2005 primarily due to an increase in revenues for transporting gas for industrial customers.

Purchased Power

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Purchased Power:	$	92,148	$	78,724		17.1	%
Purchased Power in thousands of MWhs		1,309		1,400		-6.5	%
Average cost per MWh of Purchased Power	$	70.40	$	56.23		25.2	%

     Purchased power costs increased for the three months ended March 31, 2006 as compared to the same period in 2005 primarily due to higher prices of purchased power. Volumes decreased due to milder winter weather and a large industrial customer moving to distribution only service.

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Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Fuel for Power Generation	$	53,287	$	54,362		-2.0	%
Thousands of MWh generated		966		1,071		-9.8	%
Average fuel cost per MWh of Generated Power	$	55.16	$	50.76		8.7	%

     Fuel for power generation and MWh generated decreased for the three months ended March 31, 2006 as compared to the same period in 2005 due to milder winter weather and a large industrial customer transitioning to distribution only services. The increase in average fuel cost per MWh increased primarily due to the increase in natural gas and coal prices. SPPC’s hedging strategies, as discussed in the 2005 10-K Energy Supply (Utilities), partially offset the natural gas price increases.

Gas Purchased for Resale

	Three Months Ended March 31,
					Change from
	2006		2005		Prior Year %
Gas Purchased for Resale	$	67,396	$	53,480		26.0	%
Gas Purchased for Resale (in thousands of decatherms)		7,457		7,359		1.3	%
Average cost per decatherm	$	9.04	$	7.27		24.3	%

     The cost of gas purchased for resale increased for the three months ended March 31, 2006 as compared to the same period in 2005 due to increases in natural gas prices.

Deferred Energy Costs

	Three Months Ended March 31,
						Change from
	2006		2005			Prior Year %
Deferred energy costs — electric — net	$	905	$	4,293			-78.9	%
Deferred energy costs — gas — net		4,731		(328	)		N/A
Total	$	5,636	$	3,965

     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 for 2006 and 2005 reflect amortization of deferred energy costs of $11.2 million and $9.1 million, respectively; and an under-collection of amounts recoverable in rates of $10.3 million and $4.8 million, respectively.

     Deferred energy costs — gas — net for 2006 and 2005 reflect amortization of deferred energy costs of $3.0 million and $(0.4) million, respectively; and an over-collection of amounts recoverable in rates of $1.6 million and $0.1 million, respectively.

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Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended March 31,
					Change from Prior
	2006		2005		Year %
Allowance for other funds used during construction	$	703	$	319		N/A
Allowance for borrowed funds used during construction		630		290		N/A
	$	1,333	$	609		N/A

     AFUDC for SPPC is higher for the three months ended March 31, 2006 compared to the same period in 2005 due to an increase in Construction Work-In-Progress (CWIP). The primary driver for the increase of CWIP is the expansion of the Tracy Generation Plant.

Other (Income) and Expense

	Three Months Ended March 31,
							Change from
	2006			2005			Prior Year %
Other operating expense	$	34,175		$	34,769			-1.7	%
Maintenance expense	$	7,773		$	5,991			29.7	%
Depreciation and amortization	$	23,224		$	22,387			3.7	%
Interest charges on long-term debt	$	17,690		$	17,307			2.2	%
Interest charges-other	$	1,096		$	1,146			-4.4	%
Interest accrued on deferred energy	$	(1,933	)	$	(1,583	)		22.1	%
Other income	$	(2,148	)	$	(971	)		N/A
Other expense	$	2,524		$	1,640			53.9	%

     Other operating expense decreased for the three months ended March 31, 2006 compared to the same period in 2005 primarily due to a decrease in legal fees and costs incurred for the reorganization of SPPC, NPC and SPR in 2005. Partially offsetting these items were increases in software licensing fees and other items, none of which were individually significant.

     Maintenance expense increased for the three-month period ended March 31, 2006 compared to the same period in 2005 due to outages scheduled at Tracy during the first quarter of 2006.

     Depreciation and amortization expenses were higher for the three months ended March 31, 2006 compared to the same period in 2005 primarily as a result of increases to plant-in-service.

     Interest charges on long-term debt for the three months ended March 31, 2006 were comparable to the same period in 2005. 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 ended March 31, 2006 decreased compared to the same period in 2005 due to settlements in 2005 with terminated energy suppliers which reduced associated interest costs on the terminated supplier balances, offset partially by higher miscellaneous interest charges.

     Interest accrued on deferred energy costs was higher in 2006 due to higher deferred energy balances during the three months in 2006, when compared to the same period in 2005. See Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements for further details of deferred energy balances.

     Other income increased during the three months ended March 31, 2006, when compared to the same period in 2005, due to interest income earned on cash received from the issuance of the Series M Notes issued in March 2006 and gains from the sale of property.

     Other expense increased during the three months ended March 31, 2006, when compared to the same period in 2005, due primarily to non-utility lease expenses, donations, advertising, and pension costs.

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ANALYSIS OF CASH FLOWS

     SPPC’s cash flows increased during the three months ended March 31, 2006 compared to the same period in 2005 as a result of an increase in cash flows from financing activities offset by an increase in cash used in investing activities and a decrease in cash from operations.

     SPPC borrowed approximately $198 million under its revolving credit facility to retire approximately $188 million of SPPC’s Medium Term Series A, B and C Notes. Additionally, SPPC issued $300 million 6.0% General and Refunding Mortgage Notes, Series M to pay the $198 million borrowed under the revolving credit facility. SPPC intends to use a portion of the remaining proceeds to pay for future redemptions and payments of maturing debt of approximately $81 million. Additionally, SPPC paid dividends to SPR of approximately $9.6 million.

     Cash used by investing activities increased primarily as a result of the expansion of the Tracy plant. Cash from operating activities were slightly lower in 2006 mainly due to the Enron settlement.

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, natural gas, other operating expenses and interest. SPPC had cash and cash equivalents of approximately $152.9 million at March 31, 2006. As of April 28, 2006, SPPC had $337.4 million available under its existing revolving credit facility as discussed in financing transactions.

     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 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.

     During the three months ended March 31, 2006, there were no material changes to contractual obligations as set forth in SPPC’s 2005 Form 10-K except for certain financing transactions as discussed below and certain equipment and construction service contracts to build SPPC’s 514 MW combined cycle natural gas power plant at its Tracy Generating Station, with expected completion in 2008. Obligations under the contracts total approximately $329 million.

Financing Transactions

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 to redeem the following:

• 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 $20 million aggregate principal amount of SPPC Collateralized Medium-Term 6.81% to 6.83% Series C Notes due 2006,

The remaining proceeds of $112 million will be used as follows:

• payment of approximately $51 million in connection with the redemption of SPPC’s Series A Preferred Stock on June 1, 2006. The stock will be redeemed at a redemption price per share of $25.683, plus accrued dividends to the redemption date of $.4875 per share. As of March 31, 2006, there were 2 million shares outstanding;

• payment for maturing debt of $10 million aggregate principal amount of SPPC Collateralized Medium Term 6.81% Series C Notes due April 2006;

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

• payment of related fees and for general corporate purposes.

Revolving Credit Facility

     On April 19, 2006, SPPC increased the size of its amended and restated revolving credit facility to $350 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of March 31, 2006, SPPC had $10.8 million of letters of credit outstanding and had no amounts borrowed

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under the revolving credit facility. As of April 28, 2006, SPPC had $12.6 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 March 31, 2006, SPPC was in compliance with these covenants.

     The SPPC Credit Agreement provides 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.

     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 10, Debt Covenant Restrictions.

Factors Affecting Liquidity

Limitations on Indebtedness

     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.

Mortgage Indentures

     SPPC’s First Mortgage Indenture creates a first priority lien on substantially all of SPPC’s properties in Nevada and California. As of March 31, 2006, $299.3 million of SPPC’s first mortgage bonds were outstanding. SPPC agreed in 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 March 31, 2006, there were $1.0 billion of SPPC’s General and Refunding Mortgage securities outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

1.	70% of net utility property additions,
2.	the principal amount of retired General and Refunding Mortgage bonds, and/or
3.	the principal amount of first mortgage bonds retired after April 8, 2002.

     On the basis of (1), (2) and (3) above, and on plant accounting records as of March 31, 2006, SPPC had the capacity to issue approximately $169 million of additional General and Refunding Mortgage securities. This number does not reflect the April 2006 issuance of $100 million of G&R bonds to secure the increased revolving credit facility.

     Although SPPC has capacity to issue additional General and Refunding Mortgage securities on the basis of property additions and retired securities, the financial covenants contained in the Revolving Credit Agreement limit the amount of additional indebtedness that SPPC may issue and the reasons for which such indebtedness may be issued.

     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 bonds 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 other indebtedness) 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.

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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 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 California Public Utilities Commission (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 Integrated Resource Plans (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 March 31, 2006, NPC’s and SPPC’s balance sheet included approximately $403 and $110 million, respectively, of deferred energy costs, $171.5 million of which have been requested in NPC’s 2006 Deferred Energy case and $46.7 million of which have been requested in SPPC’s Deferred Energy case discussed below. As of March 31, 2006, recovery of approximately $97.6 million and $23.9 million of the $403 and $110 million had been previously approved for collection over various periods. Refer to Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements. The remaining amounts will be requested in future regulatory filings.

     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

• NPC 2006 Deferred Energy and BTER Update — Application to create a new Deferred Energy Accounting Adjustment (DEAA) rate and to update the Base Tariff Energy Rate (BTER). Refer to the “Recently Approved Rate Cases” for the outcome of the BTER phase of this rate case. In the Deferred Energy phase, NPC requested changes to the DEAA rates such that on August 1, 2006 NPC would begin collecting $171.5 million of deferred costs for purchased fuel and power. The requested DEAA rate would increase current rates by approximately 9.3%.

• SPPC December 2005 Deferred Energy and BTER Update — Application to create a new Electric DEAA rate and to update the Electric BTER. Refer to the “Recently Approved Rate Cases” for the outcome of the BTER phase of this rate case. In the Deferred Energy phase, SPPC requested a change to the BTER rate such that on July 1, 2006 SPPC would begin collecting $46.7 million of deferred costs for purchased fuel and power. The requested DEAA rate would increase current rates by approximately 6.1%.

• 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 June and the rates to become effective in July 2006.

• 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 last part of 2006.

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Recently Approved Rate Cases

• NPC 2006 BTER Update – On April 12, 2006, the PUCN approved a new BTER, which will increase purchased fuel and power revenues by an estimated $111.7 million.

• SPPC December 2005 Electric BTER Update – On April 12, 2006, the PUCN approved a new Electric BTER, which will increase purchased fuel and power revenues by an estimated $31 million.

• SPPC 2005 Electric General Rate Case – On April 26, 2006, the PUCN voted to approve a draft order authorizing 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 26, 2006, the PUCN voted to approve a draft order authorizing 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 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.

     On April 12, 2006, the PUCN approved an agreement among the interveners and NPC, which, effective May 1, 2006, sets NPC’s BTER rates such that an estimated $111.7 million of new revenues will be collected for fuel and power purchase in addition to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the $120.1 million increase represents an overall average rate increase of approximately 6.5%.

     NPC’s request for authorization to begin a one year recovery of the $171.5 million of previously incurred purchased fuel and power cost on August 1, 2006 is pending. The requested DEAA adjustment represents an additional rate increase of approximately 9.3%. Intervener testimony addressing the deferred cost balances is due May 26, 2006 and the DEAA hearings are scheduled to begin June 20, 2006 and the PUCN decision is expected before the August 1, 2006 requested implementation date.

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 is 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.

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 5, 2006, NPC reached agreement with the PUCN Staff and the BCP, which, if approved by the PUCN, will authorize NPC to invest $37 million in land and land rights and to include authorized investments in the rate base calculation of its next general rate case. On April 26, 2006, the PUCN approved the stipulation.

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Sierra Pacific Power Company

December 2005 Deferred Energy and BTER Update

     On December 1, 2005, SPPC filed an electric DEAA rate case application with the PUCN. The application sought recovery for 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.

     SPPC’s request for authorization to begin a one year recovery of the $46.7 million of previously incurred purchased fuel and power costs on July 1, 2006 is pending. The requested DEAA rate would increase current rates by approximately 6.1%. Intervener testimony addressing the recovery of previously incurred purchased fuel and power costs was filed on May 3, 2006. Hearings are scheduled to begin May 31, 2006 and the PUCN’s decision is expected to be issued in June 2006.

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 26, 2006, the PUCN voted to change electric and gas general rates. The PUCN vote resulted in the following significant items:

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

• Gas general revenue increase: $4.5 million 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 to recover SPPC’s allocated amount of the 1999 NPC/SPPC merger costs from Electric customers

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

• New depreciation rates for Gas and Electric facilities

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

Nevada Power Company and Sierra Pacific Power Company

Renewable Portfolio Compliance Plan

     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 portfolio energy credits. The Utilities requested an exemption from the PUCN for the solar portion of the portfolio standard. Past filings have not resulted in monetary fines, but the PUCN regulations allow for such 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.

     If approved, SPPC anticipates it will begin recovering these deferred costs in the third quarter of 2006.

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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 June 2006. The earliest rates will become effective is July 1, 2006.

RECENT PRONOUNCEMENTS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

     As of March 31, 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 and preferred trust securities. 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		$	694,335
Average Interest Rate		—			—			—			—			—			7.86	%		7.86	%
NPC
Fixed Rate	$	157,559		$	17		$	13		$	162,500		$	—		$	1,793,500		$	2,113,589		$	2,175,371
Average Interest Rate		8.27	%		8.17	%		8.17	%		10.88	%		—			6.96	%		7.36	%
Variable Rate										$	15,000		$	275,000		$	100,000		$	390,000		$	390,000
Average Interest Rate											3.00	%		5.54	%		3.00	%		4.79	%
SPPC
Fixed Rate	$	31,695		$	2,400		$	322,400		$	600		$	—		$	749,250		$	1,106,345		$	1,119,414
Average Interest Rate		6.67	%		6.40	%		7.99	%		6.40	%		—			6.09	%		6.66	%
Total Debt	$	189,254		$	2,417		$	322,413		$	178,100		$	275,000		$	3,301,892		$	4,269,076		$	4,379,120

Commodity Price Risk

     See the 2005 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 $45.1 million as of March 31, 2006, which decreased significantly from December 31, 2005. The markets continued to fall during the first quarter of 2006 from the 2005 spikes as a result of hurricanes Katrina and Rita in 2005. 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.

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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 March 31, 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 financial reporting in the first quarter of 2006 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

     FERC Gaming and Partnership Show Cause Proceeding

     On June 25, 2003, FERC commenced two separate cases involving Enron Power Marketing Inc.’s (“Enron”) illicit trading activity in California with various counterparties, including the People of the State of California, California state entities, California utilities and other non-Californian entities (including NPC and SPPC). In 2004, FERC consolidated the proceedings and announced that “Enron potentially could be required to disgorge profits for all of its wholesale power sales in the Western Interconnect for the period January 16, 1997 to June 15, 2003.” On March 11, 2005, FERC clarified that Enron’s profits under the terminated power contracts fell within the scope of that proceeding.

     On February 1, 2006, the Utilities completed the settlement of long-term, ongoing litigation involving Enron’s market manipulation during the Western United States energy crisis and Enron’s claims with respect to terminated purchase power contracts between Enron and the Utilities in accordance with the terms of the Settlement Agreement, entered into as of November 15, 2005 among the Utilities, Enron, and other related Enron affiliates (the “Settlement Agreement”).

     In accordance with the terms of the Settlement Agreement, the Utilities withdrew from further participation in the Gaming and Partnership Show Cause Proceeding (including any associated appeals) as against Enron. The Utilities retained, however, all rights to participate in any allocation phase that may follow. The Utilities are unable to predict the outcome of the proceedings before the FERC at this time.

     FERC 206 complaints

     In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis.

     On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. On July 28, 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June 26, 2003 decision. The Utilities appealed this decision to the Ninth Circuit. Oral argument was held on December 8, 2004. A decision remains pending. The Utilities are unable to predict the outcome of this appeal at this time.

     The Utilities have since negotiated settlements with Duke Energy Trading and Marketing, Reliant Energy Services, Inc., Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., and Enron, but have been unable to reach agreement in bilateral settlement discussions with other respondents.

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

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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.

     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. A decision is not expected for several months thereafter. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Sierra Pacific Power Company

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 Piñon Pine unit. 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.

Sierra Pacific Resources and Nevada Power Company

Merrill Lynch/Allegheny Lawsuit

     In May 2003, SPR and NPC filed suit against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc. and Allegheny Energy Supply Co., LLC (collectively, Allegheny) in the United States District Court, District of Nevada, for compensatory and punitive damages of $850 million for causing the Public Utilities Commission of Nevada to disallow a $180 million rate adjustment for NPC in its 2001 deferred energy case (as discussed above). The PUCN held that NPC acted imprudently when it refused to enter into an electricity supply contract with Merrill Lynch and subsequently paid too much for electricity from another source. SPR and NPC allege that Merrill Lynch and Allegheny’s fraudulent testimony and wrongful conduct caused the PUCN disallowance. Merrill Lynch filed motions to dismiss on May 6, 2003 and June 23, 2003. The court has yet to rule on the motions to dismiss and the case is currently stayed pending resolution of NPC’s appeal of the 2001 deferred energy case currently pending before the Nevada Supreme Court.

Lawsuit Against Natural Gas Providers

     On April 21, 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders. On July 3, 2003, SPR and NPC filed a First Amended Complaint. A Second Amended Complaint was filed on June 4, 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric. The defendants filed motions to dismiss, which were granted by the District Court. SPR and NPC appealed the decision to the Ninth Circuit Court of Appeals. Briefing has been completed. Oral argument has not been scheduled. At this time, management cannot predict the timing or outcome of a decision on this matter.

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Other Legal Matters

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

Environmental

Nevada Power Company

Mohave Generation Station

     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 are not met. The estimated cost of new pollution controls to meet the limits, and other capital investments is $1.2 billion. Should such investments be undertaken in the future, as a 14% owner in Mohave, NPC’s cost would be $168 million.

     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.

     Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE’s share of Mohave. On October 20, 2004, the CPUC issued a proposed decision which, among other things, directed SCE to continue negotiations with the Tribes regarding post-2005 coal and water supply, and directed SCE to conduct a study of potential alternatives to Mohave.

     Because coal and water supplies necessary for long-term operation of Mohave have yet to be secured, SCE and the other Mohave co-owners (the “Owners”) have been prevented from commencing the installation of extensive pollution control equipment that must be put in place to meet the emission limits contained in the decree. 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 installation of required pollution control equipment. Thus, the Owners suspended operation of the plant on December 31, 2005, pending resolution of these issues. It is the Owners’ intent to preserve their ability to restart the plant at a later date should these issues be resolved, and economic analysis at that time support such a decision. NPC’s ownership interest in Mohave comprised approximately 10% of NPC’s peak generation capacity.

     The co-tenancy agreement and the operating agreement between the Owners expires on July 1, 2006. The Owners have been 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 if they do not choose to continue to participate in future operations.

     See further discussion of Mohave under Note 6, Commitments and Contingencies.

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 to satisfy the NDEP order expended to date are approximately $26.7 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)

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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.

     NPC is engaged in an ongoing dialogue and settlement discussions with NDEP and the EPA and DOJ regarding the NOAVs. Management has booked a minimum liability with respect to these matters; however, because management cannot predict at this time whether a final settlement will be reached, it cannot accurately predict the cost of 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. Any environmental controls and equipment changes needed to assure compliance with existing or modified regulations will be submitted by NPC to the PUCN for approval.

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 Department of Justice, 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 unable to predict the outcome of this action.

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.

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 2005Form 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.

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     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.

     On January 17, 2006, NPC filed its annual deferred energy rate case seeking to recover past costs of $171.5 million and to increase going-forward rates by $138 million. The filing requested an overall 9% increase to recover past costs and an 8% increase to going-forward rates. On April 12, 2006, the PUCN approved a stipulation that provided for an increase of approximately 6.5% totaling $120.1 million in NPC’s going-forward rates. On December 1, 2005, SPPC filed its annual deferred energy rate case seeking to recover past costs of $46.7 million and to increase going-forward rates by $53 million. On April 12, 2006, the PUCN approved an overall 3.5% increase totaling $31 million in SPPC’s going-forward electric rates. Decisions on the other portions of NPC’s and SPPC’s deferred energy rate cases filed with the PUCN are expected in the second quarter of 2006. On April 3, 2006, SPPC also requested from the California Public Utilities Commission an $11.2 million annual revenue increase 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. As of March 31, 2006, NPC’s and SPPC’s unapproved deferred energy costs, including claims for terminated energy supply contracts, were $305.4 million and $86 million, respectively, and SPPC’s unapproved gas deferred energy costs were $484 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.

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     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, their PUCN orders and, in the case of SPPC, under the terms of its restated articles of incorporation. 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 E 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 $15 million and $25 million, respectively, 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. In the first quarter of 2006, SPR received approximately $25.9 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, guarantee holders and preferred stockholders. As of April 28, 2006, the Utilities had approximately $3.7 billion of debt outstanding and SPPC had approximately $50 million stated value of preferred stock outstanding. The terms of SPR’s indebtedness restrict the amount of additional indebtedness that SPR and the Utilities may issue. Based on SPR’s March 31, 2006 financial statements, assuming an interest rate of 6.0%, SPR’s indebtedness restrictions would allow SPR and the Utilities to issue up to approximately $262 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.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

     (a) Exhibits filed with thisForm 10-Q:

Nevada Power Company:

Exhibit 4.1 Officer’s Certificate dated April 3, 2006, establishing the terms of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036.

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Exhibit 4.2	Form of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Appendix A to Exhibit 4.1 above).
Exhibit 4.3	Registration Rights Agreement dated April 3, 2006 among Nevada Power Company, Lehman Brothers Inc. and Wachovia Capital Markets, LLC, as representatives of the initial purchasers.
Exhibit 10.1	Amendment and Consent, dated April 19, 2006, to the Second Amended and Restated Credit Agreement, dated as of November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein.

Sierra Pacific Power Company:

Exhibit 4.4.	Officer’s Certificate dated March 23, 2006, establishing the terms of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016.
Exhibit 4.5	Form of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Appendix A to Exhibit 4.4 above).
Exhibit 4.6	Registration Rights Agreement dated March 23, 2006 among Sierra Pacific Power Company, Citigroup Global Markets Inc. and UBS Securities LLC, as representatives of the initial purchasers.
Exhibit 10.2	Amendment and Consent, dated April 19, 2006, to the Amended and Restated Credit Agreement, dated as of November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein.

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.

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SIGNATURES

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

	Sierra Pacific Resources (Registrant)
Date: May 5, 2006	By:	/s/ Michael W. Yackira
		Michael W. Yackira
		Corporate Executive Vice President Chief Financial Officer (Principal Financial Officer)

Date: May 5, 2006	By:	/s/ John E. Brown
		John E. Brown
		Controller (Principal Accounting Officer)

	Nevada Power Company (Registrant)
Date: May 5, 2006	By:	/s/ Michael W. Yackira
		Michael W. Yackira
		Executive Vice President Chief Financial Officer (Principal Financial Officer)

Date: May 5, 2006	By:	/s/ John E. Brown
		John E. Brown
		Controller (Principal Accounting Officer)

	Sierra Pacific Power Company (Registrant)
Date: May 5, 2006	By:	/s/ Michael W. Yackira
		Michael W. Yackira
		Executive Vice President Chief Financial Officer (Principal Financial Officer)

Date: May 5, 2006	By:	/s/ John E. Brown
		John E. Brown
		Controller (Principal Accounting Officer)

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