Nevada Power (NVP) 10-Q 2007 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, 2007

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                                                88-0198358                                   Nevada

                                      P.O. Box 10100

                                      (6100 Neil Road)

                                      Reno, Nevada 89520-0400 (89511)

                                      (775) 834-4011

2-28348                        NEVADA POWER COMPANY                                                 88-0420104                                   Nevada

                                      6226 West Sahara Avenue  

                                      Las Vegas, Nevada 89146

                                      (702) 367-5000

0-00508                        SIERRA PACIFIC POWER COMPANY                                   88-0044418                                   Nevada

                                      P.O. Box 10100

                                      (6100 Neil Road)

                                      Reno, Nevada 89520-0400 (89511)

                                      (775) 834-4011

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes   X     No____ (Response applicable to all registrants)

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

Sierra Pacific Resources:             Large accelerated filer  x     Accelerated filer  ¨     Non-accelerated filer  ¨    

Nevada Power Company:           Large accelerated filer  ¨      Accelerated filer  ¨     Non-accelerated filer  x     

Sierra Pacific Power Company:   Large accelerated filer  ¨      Accelerated filer  ¨     Non-accelerated filer  x     

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes  ¨    No  x (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                                                                                                         

                  Common Stock, $1.00 par value                                                                                   Outstanding at May 2, 2007

                     of Sierra Pacific Resources                                                                                               221,254,641 Shares

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

Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 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.

1

	SIERRA PACIFIC RESOURCES NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY QUARTERLY REPORTS ON FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2007
	CONTENTS
	PART I - FINANCIAL INFORMATION
ITEM 1.	Financial Statements
Sierra Pacific Resources
	Consolidated Balance Sheets - March 31, 2007 and December 31, 2006	3
	Consolidated Income Statements - Three Months Ended March 31, 2007 and 2006	4
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2007 and 2006	5
Nevada Power Company
	Consolidated Balance Sheets - March 31, 2007 and December 31, 2006	6
	Consolidated Income Statements - Three Months Ended March 31, 2007 and 2006	7
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2007 and 2006	8
Sierra Pacific Power Company -
	Consolidated Balance Sheets - March 31, 2007 and December 31, 2006	9
	Consolidated Income Statements - Three Months Ended March 31, 2007 and 2006	10
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2007 and 2006	11
	Condensed Notes to Consolidated Financial Statements	12
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	Sierra Pacific Resources	27
	Nevada Power Company	31
	Sierra Pacific Power Company	37
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	47
ITEM 4.	Controls and Procedures	47
	PART II - OTHER INFORMATION
ITEM 1.	Legal Proceedings	48
ITEM 1A.	Risk Factors	48
ITEM 4.	Submission of Matters to a Vote of Security Holders	48
ITEM 5.	Other Information	48
ITEM 6.	Exhibits	49
	Signature Page and Certifications	50

2

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	March 31,		December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	8,040,759	$	7,954,337
Less accumulated provision for depreciation		2,379,717		2,333,357
		5,661,042		5,620,980
Construction work-in-progress		646,402		466,018
		6,307,444		6,086,998
Investments and other property, net		34,460		34,325
Current Assets:
Cash and cash equivalents		156,525		115,709
Accounts receivable less allowance for uncollectible accounts:
2007-$37,154; 2006-$39,566		366,810		415,082
Deferred energy costs - electric (Note 1)		232,638		168,260
Deferred energy costs - gas (Note 1)		656		-
Materials, supplies and fuel, at average cost		104,374		103,757
Risk management assets (Note 5)		40,163		27,305
Deferred income taxes		32,804		55,546
Deposits and prepayments for energy		5,211		15,968
Other		35,484		31,580
		974,665		933,207
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		292,622		382,286
Deferred energy costs - gas (Note 1)		1,196		-
Regulatory tax asset		261,362		263,170
Regulatory asset for pension plans		219,921		223,218
Other regulatory assets		679,820		668,624
Risk management assets (Note 5)		18,595		7,586
Risk management regulatory assets - net (Note 5)		9,707		122,911
Unamortized debt issuance costs		64,795		67,106
Other		66,403		42,645
		1,614,421		1,777,546
TOTAL ASSETS	$	8,930,990	$	8,832,076
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity	$	2,642,158	$	2,622,297
Long-term debt		4,147,322		4,001,542
		6,789,480		6,623,839
Current Liabilities:
Current maturities of long-term debt		8,625		8,348
Accounts payable		276,423		282,463
Accrued interest		71,095		56,426
Accrued salaries and benefits		25,888		33,146
Current income taxes payable		-		5,914
Risk management liabilities (Note 5)		41,018		123,065
Accrued taxes		9,297		6,290
Other current liabilities		66,898		60,422
		499,244		576,074
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		755,187		791,428
Deferred investment tax credit		34,348		35,218
Regulatory tax liability		33,260		34,075
Customer advances for construction		97,618		91,895
Accrued retirement benefits		233,081		226,420
Risk management liabilities (Note 5)		3,991		10,746
Regulatory liabilities		308,478		301,903
Other		176,303		140,478
		1,642,266		1,632,163
TOTAL CAPITALIZATION AND LIABILITIES	$	8,930,990	$	8,832,076
The accompanying notes are an integral part of the financial statements.

3

SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
	Three Months Ended
	March 31,
	2007			2006
OPERATING REVENUES:
Electric	$	671,044		$	620,047
Gas		85,120			86,725
Other		267			284
		756,431			707,056
OPERATING EXPENSES:
Operation:
Purchased power		178,904			253,744
Fuel for power generation		228,154			143,109
Gas purchased for resale		71,646			67,396
Deferral of energy costs - electric - net		40,793			4,072
Deferral of energy costs - gas - net		(1,945	)		4,731
Other		84,747			90,276
Maintenance		23,745			21,930
Depreciation and amortization		56,233			57,461
Taxes:
Income tax benefits		(755	)		(6,904	)
Other than income		12,979			11,664
		694,501			647,479
OPERATING INCOME		61,930			59,577
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,567			6,132
Interest accrued on deferred energy		4,614			8,716
Carrying charge for Lenzie		10,082			4,031
Reinstated interest on deferred energy (Note 3)		11,076			-
Other income		7,306			9,263
Other expense		(4,916	)		(4,718	)
Income taxes		(11,383	)		( 8,185	)
		23,346			15,239
Total Income Before Interest Charges		85,276			74,816
INTEREST CHARGES:
Long-term debt		66,449			73,383
Other		8,554			5,218
Allowance for borrowed funds used during construction		(5,334	)		(6,002	)
		69,669			72,599
Preferred stock dividend requirements of subsidiary		-			975
NET INCOME APPLICABLE TO COMMON STOCK	$	15,607		$	1,242
Amount per share basic and diluted - (Note 7)
Net Income applicable to common stock	$	0.07		$	0.01
Weighted Average Shares of Common Stock Outstanding - basic		221,245,427			200,868,612
Weighted Average Shares of Common Stock Outstanding - diluted		221,701,854			201,265,472
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,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	15,607		$	2,217
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		56,233			57,461
Deferred taxes and deferred investment tax credit		5,165			(1,822	)
AFUDC		(6,567	)		(12,134	)
Amortization of deferred energy costs - electric		36,134			32,560
Amortization of deferred energy costs - gas		478			3,021
Deferral of energy costs - electric		228			(37,085	)
Deferral of energy costs - gas		(2,330	)		1,592
Deferral of energy costs - terminated suppliers		-			2,309
Carrying charge on Lenzie plant		(10,082	)		(4,031	)
Reinstated interest on deferred energy		(11,076	)		-
Other, net		(3,637	)		41
Changes in certain assets and liabilities:
Accounts receivable		48,272			29,432
Materials, supplies and fuel		(617	)		(3,018	)
Other current assets		6,852			23,156
Accounts payable		8,277			(56,661	)
Payment to terminating supplier		-			(65,368	)
Proceeds from claim on terminating supplier		-			41,365
Other current liabilities		16,895			4,977
Risk Management assets and liabilities		538			(12,630	)
Other assets		-			4,537
Other liabilities		732			3,278
Net Cash provided by Operating Activities		161,102			13,197
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(301,497	)		(413,937	)
AFUDC and other charges to utility plant		6,567			12,134
Customer advances for construction		5,723			12,028
Contributions in aid of construction		19,686			7,193
Investments in subsidiaries and other property - net		(43	)		2,838
Net Cash used by Investing Activities		(269,564	)		(379,744	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			3,612
Proceeds from issuance of long-term debt		174,451			1,030,329
Retirement of long-term debt		(28,944	)		(600,126	)
Sale of common stock, net of issuance cost		3,771			(16	)
Dividends paid		-			(968	)
Net Cash from Financing Activities		149,278			432,831
Net Increase in Cash and Cash Equivalents		40,816			66,284
Beginning Balance in Cash and Cash Equivalents		115,709			172,682
Ending Balance in Cash and Cash Equivalents	$	156,525		$	238,966
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	54,333		$	75,627
Income taxes	$	4,578		$	3,159
The accompanying notes are an integral part of the financial statements

5

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	March 31,		December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	5,295,659	$	5,187,665
Less accumulated provision for depreciation		1,308,877		1,276,192
		3,986,782		3,911,473
Construction work-in-progress		291,982		238,518
		4,278,764		4,149,991
Investments and other property, net		22,307		22,176
Current Assets:
Cash and cash equivalents		75,638		36,633
Accounts receivable less allowance for uncollectible accounts:  2007-$31,294; 2006-$32,834		210,716		244,623
Deferred energy costs - electric (Note 1)		195,582		129,304
Materials, supplies and fuel, at average cost		60,864		60,754
Risk management assets (Note 5)		23,777		16,378
Deferred income taxes		24,068		72,294
Deposits and prepayments for energy		2,884		7,056
Other		23,398		19,901
		616,927		586,943
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		281,149		359,589
Regulatory tax asset		153,634		153,471
Regulatory asset for pension plans		111,988		113,646
Other regulatory assets		455,482		440,369
Risk management assets		13,696		5,379
Risk management regulatory assets - net (Note 5)		12,021		83,886
Unamortized debt issuance costs		37,693		38,856
Other		48,392		33,209
		1,114,055		1,228,405
TOTAL ASSETS	$	6,032,053	$	5,987,515
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity	$	2,176,988	$	2,172,198
Long-term debt		2,501,650		2,380,139
		4,678,638		4,552,337
Current Liabilities:
Current maturities of long-term debt		6,225		5,948
Accounts payable		160,016		148,003
Accounts payable, affiliated companies		13,246		20,656
Accrued interest		46,561		37,010
Dividends declared		-		13,472
Accrued salaries and benefits		12,147		14,989
Current income taxes payable		-		3,981
Intercompany income taxes payable		13,776		884
Risk management liabilities (Note 5)		32,380		84,674
Accrued taxes		4,666		2,671
Other current liabilities		52,241		48,298
		341,258		380,586
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		534,200		599,747
Deferred investment tax credit		14,809		15,213
Regulatory tax liability		13,086		13,451
Customer advances for construction		65,370		60,040
Accrued retirement benefits		94,013		90,474
Risk management liabilities (Note 5)		2,747		7,061
Regulatory liabilities		173,879		171,298
Other		114,053		97,308
		1,012,157		1,054,592
TOTAL CAPITALIZATION AND LIABILITIES	$	6,032,053	$	5,987,515
The accompanying notes are an integral part of the financial statements.

6

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2007			2006
OPERATING REVENUES:
Electric	$	418,165		$	381,275
OPERATING EXPENSES:
Operation:
Purchased power		95,594			161,596
Fuel for power generation		164,085			89,822
Deferral of energy costs-net		26,932			3,167
Other		50,839			54,133
Maintenance		17,464			14,157
Depreciation and amortization		35,761			34,237
Taxes:
Income tax benefits		(8,212	)		(8,095	)
Other than income		7,734			6,595
		390,197			355,612
OPERATING INCOME		27,968			25,663
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,098			5,429
Interest accrued on deferred energy		3,849			6,783
Carrying charge for Lenzie		10,082			4,031
Reinstated interest on deferred energy (Note 3)		11,076			-
Other income		5,121			4,366
Other expense		(2,042	)		(1,965	)
Income taxes		(10,578	)		(6,409	)
		20,606			12,235
Total Income Before Interest Charges		48,574			37,898
INTEREST CHARGES:
Long-term debt		39,706			42,739
Other		6,836			3,827
Allowance for borrowed funds used during construction		(2,550	)		(5,372	)
		43,992			41,194
NET INCOME (LOSS)	$	4,582		$	(3,296	)
The accompanying notes are an integral part of the financial statements.

7

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	4,582		$	(3,296	)
Adjustments to reconcile net income (loss) to net cash provided by or (used by) operating activities:
Depreciation and amortization		35,761			34,237
Deferred taxes and deferred investment tax credit		(2,645	)		(4,820	)
AFUDC		(3,098	)		(10,801	)
Amortization of deferred energy costs		24,082			21,278
Deferral of energy costs		(844	)		(24,893	)
Deferral of energy costs - terminated suppliers		-			1,607
Carrying charge on Lenzie plant		(10,082	)		(4,031	)
Reinstated interest on deferred energy		(11,076	)		-
Other, net		(4,419	)		(405	)
Changes in certain assets and liabilities:
Accounts receivable		33,908			2,611
Materials, supplies and fuel		(109	)		(4,586	)
Other current assets		675			6,004
Accounts payable		23,267			(46,598	)
Payment to terminating supplier		-			(37,410	)
Proceeds from claim on terminating supplier		-			26,391
Other current liabilities		12,649			8,424
Risk Management assets and liabilities		(458	)		(8,939	)
Other assets		-			3,572
Other liabilities		(900	)		1,846
Net Cash provided by (used by) Operating Activities		101,293			(39,809	)
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(191,294	)		(349,409	)
AFUDC and other charges to utility plant		3,098			10,801
Customer advances for construction		5,330			9,242
Contributions in aid of construction		12,302			7,075
Investments in subsidiaries and other property - net		(39	)		(67	)
Net Cash used by Investing Activities		(170,603	)		(322,358	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		125,000			541,771
Retirement of long-term debt		(3,213	)		(213,436	)
Dividends paid		(13,472	)		(17,272	)
Net Cash from Financing Activities		108,315			311,063
Net Increase (Decrease) in Cash and Cash Equivalents		39,005			(51,104	)
Beginning Balance in Cash and Cash Equivalents		36,633			98,681
Ending Balance in Cash and Cash Equivalents	$	75,638		$	47,577
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	32,572		$	40,891
Income taxes	$	4,550		$	3,159
The accompanying notes are an integral part of the financial statements

8

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
	March 31,		December 31,
	2007		2006
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,745,100	$	2,766,672
Less accumulated provision for depreciation		1,070,840		1,057,165
		1,674,260		1,709,507
Construction work-in-progress		354,420		227,500
		2,028,680		1,937,007
Investments and other property, net (Note 4)		617		609
Current Assets:
Cash and cash equivalents		58,892		53,260
Accounts receivable less allowance for uncollectible accounts:   2007-$5,860; 2006-$6,732		155,884		170,106
Deferred energy costs - electric (Note 1)		37,056		38,956
Deferred energy costs - gas (Note 1)		656		-
Materials, supplies and fuel, at average cost		43,500		42,990
Risk management assets (Note 5)		16,386		10,927
Deposits and prepayments for energy		2,327		8,912
Other		11,806		11,184
		326,507		336,335
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)		11,473		22,697
Deferred energy costs - gas (Note 1)		1,196		-
Regulatory tax asset		107,728		109,699
Regulatory asset for pension plans		105,108		106,666
Other regulatory assets		224,338		228,255
Risk management assets (Note 5)		4,899		2,207
Risk management regulatory assets - net (Note 5)		-		39,025
Unamortized debt issuance costs		17,144		17,981
Other		14,447		7,356
		486,333		533,886
TOTAL ASSETS	$	2,842,137	$	2,807,837
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	906,987	$	884,737
Long-term debt		1,095,180		1,070,858
		2,002,167		1,955,595
Current Liabilities:
Current maturities of long-term debt		2,400		2,400
Accounts payable		89,407		89,743
Accounts payable, affiliated companies		15,982		11,769
Accrued interest		20,059		7,200
Dividends declared		-		6,736
Accrued salaries and benefits		11,997		15,209
Intercompany income taxes payable		6,860		9,055
Deferred income taxes		8,739		8,881
Risk management liabilities (Note 5)		8,638		38,391
Accrued taxes		4,347		3,407
Other current liabilities		14,658		12,125
		183,087		204,916
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes		276,364		278,515
Deferred investment tax credit		19,539		20,005
Regulatory tax liability		20,174		20,624
Customer advances for construction		32,248		31,855
Accrued retirement benefits		127,142		124,254
Risk management liabilities (Note 5)		1,244		3,685
Risk management regulatory liability - net (Note 5)		2,314		-
Regulatory liabilities		134,599		130,605
Other		43,259		37,783
		656,883		647,326
TOTAL CAPITALIZATION AND LIABILITIES	$	2,842,137	$	2,807,837
The accompanying notes are an integral part of the financial statements.

9

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2007			2006
OPERATING REVENUES:
Electric	$	252,879		$	238,772
Gas		85,120			86,725
		337,999			325,497
OPERATING EXPENSES:
Operation:
Purchased power		83,310			92,148
Fuel for power generation		64,069			53,287
Gas purchased for resale		71,646			67,396
Deferral of energy costs - electric - net		13,861			905
Deferral of energy costs - gas - net		(1,945	)		4,731
Other		32,848			34,175
Maintenance		6,281			7,773
Depreciation and amortization		20,472			23,224
Taxes:					-
Income taxes		8,360			6,849
Other than income		5,186			5,018
		304,088			295,506
OPERATING INCOME		33,911			29,991
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		3,469			703
Interest accrued on deferred energy		765			1,933
Other income		1,831			2,148
Other expense		(2,014	)		(2,524	)
Income taxes		(1,211	)		(823	)
		2,840			1,437
Total Income Before Interest Charges		36,751			31,428
INTEREST CHARGES:
Long-term debt		16,108			17,690
Other		1,459			1,096
Allowance for borrowed funds used during construction and capitalized interest		(2,784	)		(630	)
		14,783			18,156
NET INCOME		21,968			13,272
Dividend Requirements of preferred stock		-			975
EARNINGS APPLICABLE TO COMMON STOCK	$	21,968		$	12,297
The accompanying notes are an integral part of the financial statements.

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	21,968		$	13,272
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		20,472			23,224
Deferred taxes and deferred investment tax credit		1,142			(41,878	)
AFUDC		(3,469	)		(1,333	)
Amortization of deferred energy costs - electric		12,052			11,282
Amortization of deferred energy costs - gas		478			3,021
Deferral of energy costs - electric		1,072			(12,192	)
Deferral of energy costs - gas		(2,330	)		1,592
Deferral of energy costs - terminated suppliers		-			702
Other, net		1,881			1,090
Changes in certain assets and liabilities:
Accounts receivable		14,222			53,301
Materials, supplies and fuel		(510	)		1,584
Other current assets		5,960			16,770
Accounts payable		(471	)		13,414
Payment to terminating supplier		-			(27,958	)
Proceeds from claim on terminating supplier		-			14,974
Other current liabilities		13,119			6,921
Risk Management assets and liabilities		996			(3,691	)
Other assets		-			965
Other liabilities		977			4,019
Net Cash provided by Operating Activities		87,559			79,079
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant		(110,203	)		(64,528	)
AFUDC and other charges to utility plant		3,469			1,333
Customer advances for construction		393			2,786
Contributions in aid of construction		7,384			118
Investments in subsidiaries and other property - net		(8	)		13
Net Cash used by Investing Activities		(98,965	)		(60,278	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			3,612
Proceeds from issuance of long-term debt		49,451			488,557
Retirement of long-term debt		(25,677	)		(386,608	)
Dividends paid		(6,736	)		(9,604	)
Net Cash from Financing Activities		17,038			95,957
Net Increase in Cash and Cash Equivalents		5,632			114,758
Beginning Balance in Cash and Cash Equivalents		53,260			38,153
Ending Balance in Cash and Cash Equivalents	$	58,892		$	152,911
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	3,385		$	12,274
Income taxes	$	28		$	-
The accompanying notes are an integral part of the financial statements

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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). 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, 2006 (the “2006 Form 10-K”).

The results of operations and cash flows of SPR, NPC and SPPC for the three months ended March 31, 2007, are not necessarily indicative of the results to be expected for the full year.

Carrying Charge on the Lenzie Generating Station

In 2004, the Public Utilities Commission of Nevada (PUCN) granted NPC’s request to designate the Chuck Lenzie Generating Station (Lenzie) as a critical facility and allowed a 2% enhanced Return on Equity (ROE) to be applied to the Lenzie construction costs expended after acquisition. The order allowed for an additional 1% enhanced ROE if the two Lenzie generating units were brought on line early. In addition, the PUCN granted NPC’s request to begin accumulating a carrying charge as a regulatory asset including the 3% enhanced ROE (collectively referred to as “carrying charges”), until the plant is included in rates.

Units 1 and 2 were declared commercially operable in January 2006 and April 2006, respectively, qualifying for the incentive ROE treatment. Based on the regulatory order, through March 31, 2007, NPC has accumulated approximately $50.6 million in carrying charges; however, $7.1 million of this amount has not been recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through regulated rates. For financial reporting purposes, through March 31, 2007, NPC has recognized a cumulative of $43.5 million in income, and recorded a corresponding regulatory asset, which represents only the carrying charge component associated with incurred debt costs. For the three month period ending March 31, 2007, NPC recognized $10.1 million in income.  NPC has requested recovery of $30.8 million of the carrying charges to be recovered over a 35 year period in its 2006 General Rate Case (GRC) filed in November 2006.

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 2006 Form 10-K, for additional information regarding the implementation of deferred energy accounting by the Utilities.

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The following deferred energy costs were included in the consolidated balance sheets as of March 31, 2007 (dollars in thousands):

	March 31, 2007
	NPC		SPPC			SPPC		SPR
Description	Electric		Electric			Gas		Total
Unamortized balances approved for collection in current rates
Electric - NPC Period 1 (Reinstatement of Deferred Energy)(1)	$	189,902	$	-		$	-	$	189,902
Electric - SPPC Period 3 (effective 6/05, 25 months)		-		1,885			-		1,885
Electric - NPC Period 5 (effective 8/06, 2 years)		145,246		-			-		145,246
Electric - SPPC Period 5 (effective 7/06, 2 years)		-		21,432			-		21,432
Nat Gas - P6, LPG - P5 (effective 12/06, 1 year)		-		-			446		446
Western Energy Crisis Rate Case (1)		80,096		-			-		80,096
Balances pending PUCN approval		58,951		16,220			-		75,171
Cumulative CPUC balance		-		8,113			-		8,113
Balances accrued since end of periods
submitted for PUCN approval		2,536		(15,387	)		1,406		(11,445	)
Western Energy Crisis Rate Case(2)		-		16,266			-		16,266
Total	$	476,731	$	48,529		$	1,852	$	527,112
Current Assets
Deferred energy costs - electric	$	195,582	$	37,056		$	-	$	232,638
Deferred energy costs - gas	$	-	$	-		$	656	$	656
Deferred Assets
Deferred energy costs - electric	$	281,149	$	11,473		$	-	$	292,622
Deferred energy costs - gas	$	-	$	-		$	1,196	$	1,196
Total	$	476,731	$	48,529		$	1,852	$	527,112

(1)   Rates to be effective beginning June 1, 2007. Reference discussion in Note 3, Regulatory Actions, of the Condensed Notes to Consolidated Financial Statements.

(2)   SPPC’s Western Energy Crisis Rate Case is discussed in Note 13, Commitments and Contingencies of the Notes to Financial Statements in the 2006 Form 10-K.

Recent Pronouncements

FIN 48 

In July 2006, the FASB issued FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006, and, therefore, has been adopted as of January 1, 2007, by SPR and the Utilities. As a result of the implementation of FIN 48, SPR and the Utilities recorded an increase of $487 thousand to the January 1, 2007 balance of retained earnings as a cumulative effect adjustment.

SPR and the Utilities file a consolidated U.S. federal income tax return. The U.S. federal jurisdiction is the only “major” tax jurisdiction for the Company. In connection with the previous examination cycles, the statute of limitations for tax years 1997 through 2003 was extended to December 31, 2008. The audits of tax years 1997 through 2004 have been completed, but are pending Joint Committee on Taxation notification. The statute of limitations for tax years 2004 and 2005 expire on September 15, 2008 and 2009, respectively. All earlier years are closed by statute.

SPR and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively.  The total amount of unrecognized tax benefits as of the date of adoption is $27.8 million, of which $18.2 million would affect the effective tax rate if recognized. No interest and penalties have been accrued as of the date of adoption. No significant increases or decreases to unrecognized tax benefits are expected within 12 months of this reporting date.

SFAS 159 

 In February 2007, the FASB issued FASB Statement No. 159, "The Fair Value Option for Financial Liabilities" ("SFAS 159"), which permits entities to choose to measure many financial instruments and certain other items at fair value. The objective of the statement is to improve financial reporting by providing entities with the opportunity to mitigate

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volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of SFAS 159 are effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. SPR and the Utilities are currently evaluating the potential impact of the adoption of SFAS 159.

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.

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 2006 Form 10-K. Inter-segment revenues are not material (dollars in thousands).

Three Months Ended	NPC		SPPC		Total
March 31, 2007	Electric		Electric		Electric		Gas		Other		Consolidated
Operating Revenues	$	418,165	$	252,879	$	671,044	$	85,120	$	267	$	756,431
Operating Income	$	27,968	$	28,270	$	56,238	$	5, 641	$	51	$	61,930
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	$	3,923	$	59,577

NOTE 3. REGULATORY ACTIONS

Pending Rate Cases

Nevada Power Company

NPC 2007 Deferred Energy Rate Case and BTER Update

In January 2007, NPC filed an electric Deferred Energy Accounting Adjustment (DEAA) rate case and BTER update application with the PUCN. The application seeks recovery of $75 million of deferred fuel and purchased power costs and requested to reset NPC’s going forward BTER to reflect anticipated changes in future energy costs. This application requests a 1.6% decrease in overall rates.

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

In April 2007, a stipulation between the parties was filed with the PUCN resolving all issues in this case and does not materially impact the requested rate change. The PUCN has yet to approve the stipulation.

NPC 2006 General Rate Case

In November 2006, NPC filed its statutorily required electric general rate case. This filing requests authorization to:

·   Increase annual general revenues by $172.4 million which is approximately an 8% increase

·   Set the Return on Equity and Rate of Return at 11.40% and 9.41%, respectively

·   Recover 100% of the amortization of the 1999 NPC/SPPC merger costs rather than the 80% recovery that is currently in general rates

·   Implement the PUCN’s previous orders regarding incentive ratemaking for the Chuck Lenzie Generating Station

·   Implement new depreciation rates

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In February 2007, NPC submitted its certification filing which lowered the requested ROR to 9.39% and the general revenues increase was lowered to $156.4 million, representing an overall rate increase of 7.4%.

The PUCN is expected to issue its ruling in May 2007. NPC expects the new rates to be in effect on June 1, 2007.

Sierra Pacific Power Company

SPPC 2006 Electric Deferred Energy Rate Case and BTER Update

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

In May 2007, a stipulation between the parties was filed with the PUCN resolving all issues in this case and does not materially impact the requested rate change. The PUCN has yet to approve the stipulation.

SPPC 2006 Western Energy Crisis Rate Case

In December 2006, SPPC filed an application to recover $22.6 million over four years in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the western energy crisis. This application requests an overall rate increase of 0.53%.

In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement rates on July 1, 2007 with a request to establish a regulatory asset to recover $22.6 million in deferred legal and settlement costs. SPPC further requests authority to recover carrying charges on the regulatory asset. SPPC may request authority to begin recovering the regulatory asset established by the PUCN in a future application to change rates. The parties to the stipulation have requested that the PUCN issue an order by September 30, 2007. The PUCN has set a hearing for August 2007.

Approved Rate Cases

Nevada Power Company

NPC 2007 Western Energy Crisis Rate Case

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

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

NPC 2001 Deferred Energy Case

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

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

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

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In March 2007, the PUCN approved a stipulation that authorizes NPC to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. The $189.9 million represents Nevada’s jurisdictional portion of the $178.8 million disallowance plus carrying charges of $11.1 million from the date the costs were incurred to the date of disallowance by the PUCN.

NOTE 4. LONG-TERM DEBT

 As of March 31, 2007, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the balance of 2007, for the next four years and thereafter are shown below (dollars in thousands):

	NPC			SPPC			SPR Holding Co. and Other Subs.		SPR Consolidated
2007	$	2,573		$	1,704		$	-	$	4,277
2008		7,065			322,400			-		329,465
2009		22,138			80,600	(1)		-		102,738
2010		132,843			25,000			-		157,843
2011		369,735			-			-		369,735
		534,354			429,704			-		964,058
Thereafter		1,986,113			668,250			549,209		3,203,572
		2,520,467			1,097,954			549,209		4,167,630
Unamortized Premium(Discount) Amount		(12,592	)		(374	)		1,283		(11,683	)
Total	$	2,507,875		$	1,097,580		$	550,492	$	4,155,947

(1) See Washoe County Water Facilities Refunding Revenue Bonds, below.

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

Financing Transactions (SPPC)

    Washoe County Water Facilities Refunding Revenue Bonds

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

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

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

The proceeds of the offerings were used to refund the $80 million aggregate principal amount of 5.00% Washoe County Water Facilities Revenue Bonds, Series 2001, which had a mandatory remarketing in 2009.

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

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Commodity Instruments

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

Forward Starting Swaps

In March 2007, SPPC entered into three forward-starting interest rate swap agreements, with an aggregate notional principal amount of $250 million, to manage the risk associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to $250 million fixed rate mortgage bonds expected to be issued on or before August 31, 2007. If the market swap rates are higher at the unwind date, SPPC will receive a payment for the difference between the locked swap rate and the market swap rate. If swap rates are lower at the unwind date, then SPPC will make a payment to the counterparty.

As of March 31, 2007, SPPC had a gain of $1.6 million, which was recorded as a current risk management asset with the offset recorded as a risk management regulatory liability in accordance with regulatory accounting practices under SFAS No. 71. The amount included in the risk management regulatory asset or liability at the cash settlement date will be amortized as a component of interest expense over the life of the debt.

Risk Management Assets/Liabilities

The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of SPR, NPC, and SPPC, and the related regulatory assets/liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS No. 133. The fair values of the open derivative positions are determined using quoted exchange prices, external dealer prices, and available market pricing curves. Due to deferred energy accounting treatment under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income:

	March 31, 2007 Fair Value (dollars in millions)							December 31, 2006 Fair Value (dollars in millions)
	SPR		NPC		SPPC			SPR		NPC		SPPC
Risk management assets- current	$	40.2	$	23.8	$	16.4		$	27.3	$	16.4	$	10.9
Risk management assets- noncurrent		18.6		13.7		4.9			7.6		5.4		2.2
Total risk management assets	$	58.8	$	37.5	$	21.3		$	34.9	$	21.8	$	13.1
Risk management liabilities- current	$	41.0	$	32.4	$	8.6		$	123.1	$	84.7	$	38.4
Risk management liabilities- noncurrent		3.9		2.7		1.2			10.8		7.1		3.7
Total risk management liabilities	$	44.9	$	35.1	$	9.8		$	133.9	$	91.8	$	42.1
Risk management regulatory assets (liabilities) - net	$	9.7	$	12.0	$	(2.3	)	$	122.9	$	83.9	$	39.0

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities can not predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities open derivative positions with its counterparties and the changes in forward commodity prices. The increase in net risk management assets as of March 31, 2007 as compared to December 31, 2006, is mainly due to favorable open derivative positions on natural gas options held by the Utilities to hedge energy price risk for their customers, resulting from higher commodity prices for natural gas in 2007 relative to contract prices.

Also included in total risk management assets were $ 23.5 million, $ 14.4 million, and $ 9.1 million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at March 31, 2007.

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NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental

Nevada Power Company

Reid Gardner Station

In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the following 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. Any future ponds will be double-lined with inter-liner leak detection in accordance with the NDEP Authorization to Discharge Permit issued October 2005.

Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $36 million. Expenditures for 2007 through 2010 are projected to be approximately $10 million.

As disclosed in prior filings, in June 2006, the Environmental Protection Agency (EPA) issued a Finding and Notice of Violation (NOV) related to monitoring, recordkeeping and emission exceedances at the Reid Gardner facility. In April 2007, NPC lodged a Consent Decree in federal district court with NDEP, EPA, and the Department of Justice (DOJ) regarding the NOVs and additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that will be required to resolve the alleged violations. Terms of the Consent Decree include a $1.1 million fine, funding of projects, of which NPC does not expect to be material for the Supplemental Environmental Project with the Clark County School District aimed at achieving increased energy efficiency and cost savings, and the installation of emission reduction equipment at the facility. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in NPC’s 2006 Integrated Resource Plan (IRP) filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen. Capital expenditures are estimated at $84.2 million as approved by the PUCN, however, amounts may change depending on the procurement of material and services.

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 Department of Air Quality and Environmental Management (DAQEM) 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. In October 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. In May 2006, the EPA, by letter from the DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified civil penalties, together with injunctive relief, for alleged violations of the Prevention of Significant Deterioration requirements and Title V operating permit requirements of the Clean Air Act.  NPC has entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations. Monetary penalties are not expected to be material and certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006 IRP filing.  A stipulation among the parties was submitted to the PUCN for approval.  A decision is expected in the latter part of May 2007.

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.

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

On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a motion to remand the case back to state court in St. Louis, Missouri. Joint Owners have filed a motion to dismiss the complaint for lack of jurisdiction. On May 30, 2006, the Federal District Court granted Peabody’s motion and remanded the case back to state court. On June 29, 2006, Joint Owners filed a new motion to dismiss with the Missouri state court and requested a stay of the discovery proceedings pending the ruling on the new motion. On September 21, 2006, the Missouri state court heard oral arguments on the motion to dismiss. Parties are in the process of completing briefing on the motions.  A decision is not expected until mid 2007.  Several discovery motions remain pending. NPC is unable to predict the outcome of the decisions.

Sierra Pacific Power Company

Farad Dam

SPPC owns 4 hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (Insurers) for the flume and dam. In December, 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs. In May 2005, Insurers filed a motion for summary judgment on the coverage issue, which has been denied. In October 2005, Insurers filed another (partial) summary judgment motion with respect to coverage, which the court also denied. On June 16, 2006, Insurers filed new summary judgment motions, which SPPC opposed. The matter was taken under submission by the Court. A ruling is expected mid 2007. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts or from other sources. Management has not recorded a loss contingency for this matter, as the loss, if any, can not be estimated at this time.

Piñon Pine

In its 2003 GRC, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the Project).  The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative.  Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project.  SPPC's participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan.  While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational.  After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable.  In its order in May 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).  In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). On March 27, 2006, the PUCN appealed the Order to the Nevada Supreme Court (the Supreme Court) and filed a motion to stay the Order pending the appeal to the Supreme Court. On June 12, 2006, the District Court granted PUCN’s motion to stay the Order. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and on January 18, 2007 the matter was remitted back to the

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District Court, which, consistent with its January 25, 2006 order, will remand the matter back to the PUCN for further review. In April 2007, the PUCN opened a docket to address the recoverability of expenditures for the Piñon Pine combined cycle combustion turbine project.  Hearing dates have yet to be scheduled.

Other Legal Matters

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

Regulatory Contingencies

Nevada Power Company

Mohave Generation Station (Mohave)

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

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

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of 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 2006 as the new emission limits were not met. Due to the lack of resolution regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the Consent Decree.

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

In NPC’s 2003 GRC, the PUCN ordered the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its shutdown with recovery of any accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave in rates, as such, associated savings are currently recorded as a reduction in electric operating revenues-other. NPC continues to accumulate all costs and savings associated with the shut down of Mohave, including unrecovered plant costs, in Other Regulatory Assets which has a balance of $15.4 million as of March 31, 2007. In its GRC, NPC requested further clarification on the regulatory treatment of Mohave. In the event that any portion of Mohave is disallowed, NPC will have to evaluate such portion 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.

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

	Three months ended March 31,
	2007		2006
Basic EPS
Numerator ($000)
Net income applicable to common stock	$	15,607	$	1,242
Denominator
Weighted average number of common shares outstanding		221,245,427		200,868,612
Per Share Amounts
Net income applicable to common stock	$	0.07	$	0.01
Diluted EPS
Numerator ($000)
Net income applicable to common stock	$	15,607	$	1,242
Denominator(1)
Weighted average number of shares outstanding before dilution		221,245,427		200,868,612
Stock options		151,856		73,905
Executive long term incentive plan - restricted		-		112,074
Non-Employee Director stock plan		40,665		25,287
Employee stock purchase plan		3,143		2,168
Performance Shares		260,763		183,426
		221,701,854		201,265,472
Per Share Amounts
Net income applicable to common stock	$	0.07	$	0.01

(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, 2007 and 2006, 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, 2007 and 2006, 874,823 and 923,958 shares, respectively, would be included.

NOTE 8. PENSION AND OTHER POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other post-retirement 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
	2007			2006			2007			2006
Service cost	$	5,725		$	5,758		$	768		$	883
Interest cost		9,855			9,157			2,570			2,571
Expected return on plan assets		(10,474	)		(10,182	)		(1,309	)		(1,230	)
Amortization of prior service cost		407			473			31			31
Amortization of Transition Obligation		-			-			242			242
Amortization of net (gain)/loss		1,803			2,443			815			1,154
Net periodic benefit cost	$	7,316		$	7,649		$	3,117		$	3,651

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 The amount of expected company contribution in 2007 was previously disclosed in Note 11, Retirement Plan and Post-Retirement Benefits, in the 2006 Form 10-K, were $1.5 million for the pension plan and $12.5 million for other post-retirement benefits. Management will continue to re-assess the amounts to be funded for each of the plans in 2007.

SPPC’s Bargaining Unit 1245 signed a new union agreement in March 2007. The agreement requires that certain elections be made by employees of the group. This process will be completed in the second quarter of 2007, as such, Other Post-Retirement Benefits will be re-measured at June 30, 2007. Depending on the elections made Other Post-Retirement Benefit Plan costs, the corresponding liability, and amounts funded to the plan may differ from previous disclosure.

NOTE 9.  DEBT COVENANT AND OTHER RESTRICTIONS

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 may 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. At the time of the order, SPR and the Utilities were only rated by Standard & Poor’s (S&P), Moody’s Investors Service, Inc. (Moody’s) and Fitch Ratings Ltd. (Fitch). The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies.

In addition, certain agreements entered into by the Utilities set restrictions on certain restricted payments, including the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. Additionally, covenants of certain SPR, NPC and SPPC debt limit the Utilities’ ability to incur additional debt. Material restrictions on dividends and on debt incurrence, contained in SPR’s and the Utilities’ financing agreements, are discussed in detail in the 2006 Form 10-K, Note 8, Debt Covenant and Other Restrictions.

As of March 31, 2007, 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. Were it not for the PUCN dividend restriction, NPC would be permitted to pay up to a maximum of $611 million to SPR, and SPPC would be permitted to dividend up to a maximum of $137 million to SPR, as of March 31, 2007.

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

                RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

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

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of 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)   unfavorable or untimely rulings in rate cases filed or to be filed by NPC and SPPC (collectively referred to as the Utilities) with the Public Utilities Commission of Nevada (PUCN), including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas costs recorded by SPPC for its gas distribution business;

(2)   the ability and terms upon which SPR, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of unfavorable rulings by the PUCN, untimely regulatory approval for such financings, and/or a downgrade of the current debt ratings of SPR, NPC, or SPPC;

(3)   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;

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

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

(6)   changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities;

(7)   the effect that any construction risks may have on our business, such as the risk of delays in permitting, changes in environmental laws, securing adequate skilled labor, cost and availability of materials and equipment, equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(8)   whether the Utilities can procure sufficient renewable energy sources in each compliance year to satisfy the Nevada Portfolio Standard;

(9)   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;

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

(11)   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;

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(12)   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;

(13)   the final outcome of the proceedings that remanded to the PUCN for further consideration of its decision on SPPC’s 2003 General Rate Case (GRC), which disallowed the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project;

(14)   the timing and final outcome of the PUCN’s decision regarding SPPC’s recovery of deferred energy costs associated with claims for terminated supplier contracts;

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

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

(17)   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;

(18)   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;

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

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

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

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 of 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:

• Results of Operations

• Analysis of Cash Flows

• Liquidity and Capital Resources

• Regulatory Proceedings (Utilities)

SPR’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the distribution, transmission, generation and sale of electricity and, in the case of SPPC, sale of natural gas. 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 Security Exchange Commission (SEC) reporting purposes and as such 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 2007, NPC’s revenues increased from the same period in 2006 primarily as a result of higher rates and customer growth. NPC’s net income for the first quarter of 2007 increased compared to the same period in 2006 primarily due to the carrying charge for the Lenzie Generating Station and the settlement with the Public Utilities Commission of Nevada (PUCN) regarding accrued interest on the 2001 deferred energy case.  See Note 3, Regulatory Actions, in the Condensed Notes to Financial Statements and the 2006 Form 10-K.

During the first quarter of 2007, SPPC electric revenues increased from the same period in 2006 primarily as a result of higher rates and customer growth, while gas revenues dropped slightly. Electric rates increased as a result of SPPC’s General Rate Case (GRC) and various deferred energy cases and Base Tariff Energy Rate (BTER) updates as discussed in the 2006 Form 10-K. SPPC’s gas revenues decreased primarily due to warmer weather in the first quarter in 2007 and a decrease in rates. SPPC’s net income for the first quarter of 2007 increased compared to the same period in 2006 primarily due to an increase in Allowance For Funds Used During Construction and Allowance For Borrowed Funds Used During Construction due to the construction at Tracy Generating Station.

SPR recognized net income applicable to common stock of $15.6 million for the three months ended March 31, 2007, compared to $1.2 million for the same period in 2006. Earnings increased primarily as a result of NPC’s carrying charge for the Lenzie Generating Station and the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case (see Note 3, Regulatory Actions, in the Condensed Notes to Financial Statements and the 2006 Form 10-K), and an increase in SPPC’s Allowance for funds used during construction and allowance for borrowed funds used during construction due to the construction at Tracy Generating Station.

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. Growth in Nevada continues, although at a slower pace than in 2006.  While growth in the State of Nevada, particularly in the Las Vegas area, has flattened out after the surge earlier this decade, the slower pace of housing starts has been partly offset by new casino projects in Las Vegas.  Population growth forecasts, however, may be influenced by economic trends in hotel room expansion and changes in the local housing markets. The Utilities will continue to be subject to fluctuations in the volatile energy markets to the extent that the requirements of their customers are in excess of the Utilities’ owned generation, as well as, natural gas.

With significant amounts of construction costs in the Utilities’ future, SPR and the Utilities will need to raise substantial amounts of capital to fund expenditures. As a result, reducing the cost of capital by attaining investment grade ratings for the Utilities’ secured debt has been and continues to be a significant business focus for 2007.

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Summarized below are significant business issues and challenges ahead in 2007. It is not intended to be an exhaustive discussion, nor to suggest that other issues may not arise during 2007 or thereafter. Details relating to the discussion below can be found in the Condensed Notes to the Financial Statements and elsewhere within this Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as the 2006 Form 10-K.

Generation Strategy

The Utilities’ Integrated Resource Plan (IRP) focuses on conventional generation, renewable energy, conservation, and transmission projects to meet Nevada’s growing electricity needs while diversifying the fuel mix of the Utilities’ generation portfolios. As a result, the Utilities have embarked on owning, constructing and purchasing energy to meet demand. NPC purchased and completed construction of the Lenzie Generating Station and purchased the Silverhawk facility, both of which are highly efficient natural gas burning generating stations. In 2007, NPC began construction of natural gas-fired combustion turbine peaking units at Clark Station to be installed in 2008 and 2009. SPPC is expanding at its Tracy Generating Station. Both NPC and SPPC are working on the development and construction of the Ely Energy Center, consisting of two 750-megawatt coal-fired generation units and the Utilities continue to seek opportunities to purchase renewable energy.

Coal Generating Units

Included in the PUCN’s approval of the IRP is Phase 1 of the construction of the Ely Energy Center, a major project to be located near Ely, Nevada consisting of two 750-megawatt coal-fired generation units. In addition, the PUCN approved the development and construction of a 250-mile 500kV transmission line that will deliver electricity from the Ely Energy Center as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state. The PUCN approved spending up to $300 million for development activities associated with the Ely Energy Center; however, they placed a $155 million spending limit until the appropriate air permits are obtained. The PUCN established the project as a “critical facility,” thereby allowing it to qualify for incentives that will be determined in a later filing. Additionally, the PUCN required NPC and SPPC to file amendments to their 2006 IRPs in early 2008 once elements of the plan, including final costs, can be more accurately estimated. Depending on the successful negotiation of certain contracts and permitting, the current estimate for the Ely Energy Center and the 500kV transmission line is approximately $3.8 billion.

Natural Gas Generating Units

NPC has begun the construction of 600 megawatts of natural gas-fired combustion turbine peaking units at Clark Station to be installed in 2008 and 2009 at an approximate cost of $395 million.

SPPC continues to construct a 514 Megawatt gas fired high efficiency combined cycle generator at the Tracy Plant. SPPC anticipates an in-service date of June 2008. The PUCN ordered that SPPC be allowed to include construction work in progress balances in rate base between mandated general rate cases, prior to the in-service date, and granted a 1.5% enhanced Return on Equity (ROE) for the estimated $421 million investment. The unit will provide needed generation within SPPC’s control area to reliably serve the growing needs of Northern Nevada.

For more details of NPC’s IRP and SPPC’s thirteenth amendment to its IRP, see Regulatory Proceedings, in the 2006 Form 10-K.

Renewable Energy

Nevada law sets forth the renewable energy portfolio standard (Portfolio Standard) requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable energy resources (Renewables). Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. In 2006, the Utilities were required to obtain six percent of their total energy from Renewables. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20% in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met from solar resources. In 2007 and 2008, the Utilities will be required to obtain nine percent (9%) of their total energy from Renewables. The Utilities have embarked on a strategy to invest in renewable energy that, along with third party contracts, will provide the opportunity for the Utilities to meet the Portfolio Standard as set forth by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewable energy resources.

Management of Energy Risk

The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. While NPC has greatly reduced its dependence on wholesale

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power markets to meet its customers’ demand, both Utilities continue to have a significant need to tap energy markets due to the fact that the Utilities’ owned generation is insufficient to meet their customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk -- the prospect that energy supplies will not be sufficient to fulfill customer requirements.

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

The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. Reference details of the Utilities’ energy supply plan in their 2006 Form 10-K. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.

The Utilities follow PUCN-approved energy supply plans that encompass the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for economic hedging in conjunction with energy purchases and sales are also used to mitigate these risks. The Utilities do not trade financial instruments.

Access to Capital Markets

With substantial commitments to existing and prospective construction and volatile energy costs, SPR and the Utilities’ access to capital markets, including both debt and equity, continues to be a significant business issue. Management continues to be focused on returning the Utilities’ senior secured debt to investment grade credit quality. Significant amounts of capital may be necessary to fund construction costs of generating units and, as a result, management may be required to meet such financial obligation with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and capital contributions from SPR. If energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, the Utilities may need to issue more debt to support their operating costs or may need to delay capital expenditures.

Regulatory

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for annual rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every two years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. In addition, as necessary, the Utilities can file for a change to their BTER to more closely match actual prices. The Utilities remain committed to maintaining a positive relationship with their regulators. Details regarding recently approved and pending rate cases are discussed in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements.

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 $10.9 million and $13.0 million of interest costs for the three months ended March 31, 2007 and 2006, respectively.

During the three months ended March 31, 2007, SPR recognized net income applicable to common stock of approximately $15.6 million compared to $1.2 million to the same period in 2006. The change in SPR’s consolidated earnings during the three months ended March 31, 2007 compared to the same period in 2006 was primarily due to the carrying charge for the Lenzie Generating Station, the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case and an increase in SPPC’s Allowance For Funds Used During Construction and Allowance For Borrowed Funds Used During Construction due to construction at the Tracy Generating Station.

As of March 31, 2007, NPC had paid $13.5 million in dividends to SPR and SPPC had paid $6.7 million in dividends to SPR.

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ANALYSIS OF CASH FLOWS

SPR’s cash decreased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to a decrease in cash from financing activities partially offset by an increase in cash flows from operating activities and a decrease in cash used for investing activities.

Cash flows from operating activities increased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to increased rates which affected the following:

·   increases in the collection of Accounts Receivables; and

·   BTER rates which more accurately matched purchased power and fuel for generation costs with amounts collected from customers.

Also contributing to the increase was a decrease in payments made to suppliers, due to the timing of payments, the net settlement with Enron in 2006 and payments for option premiums in 2006.

Cash flows from investing activities decreased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to NPC’s purchase of the Silverhawk Generating Station and completion of the construction of the Lenzie Generating Station in 2006, offset by increases at SPPC associated with the expansion at the Tracy Generating Station.

Cash flows from financing activities decreased during the three months ended March 31, 2007, compared to the same period in 2006 primarily due to the purchase of NPC’s Silverhawk Generating Station and construction of the Lenzie Generating Station which required significant amounts of capital in 2006. Additionally, contributing to the decrease was SPPC’s decrease in the issuance of debt and the use of its revolving credit facility to refinance debt in 2006.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Overall Liquidity

SPR’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and interest.

Available Liquidity as of March 31, 2007 (in millions)
	SPR		NPC		SPPC
Cash and Cash Equivalents	$	22.0	$	75.6	$	58.9
Balance available on Revolving Credit Facility		N/A		431.7		308.2
	$	22.0	$	507.3	$	367.1

SPR has approximately $42.5 million payable of debt service obligations for 2007, of which SPR paid approximately $18.4 million through dividends from the Utilities, during the three months ended March 31, 2007. SPR has approximately $24.1 million payable of debt service obligations remaining during 2007. SPR expects to meet its debt service obligations with cash on hand and/or through dividends from the Utilities. See Dividends from Subsidiaries below.

SPR and the Utilities anticipate that they will be able to meet operating costs such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy and external borrowings. However, to fund capital requirements, as discussed in the 2006 Form 10-K, SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the three months ended March 31, 2007, there were no material changes to contractual obligations as set forth in SPR’s 2006 Form 10-K for SPR (holding company). See NPC and SPPC’s respective sections for changes in contractual obligations.

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Factors Affecting Liquidity

Effect of Holding Company Structure

As of March 31, 2007, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $74.2 million of its unsecured 7.803% Senior Notes due 2012; $225 million of its 6.75% Senior Notes due 2017; and $250 million of its unsecured 8.625% Senior Notes due 2014.

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

As of March 31, 2007, SPR, NPC, SPPC, and their subsidiaries had approximately $4.1 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 $549 million of debt at the holding company and other subsidiaries. Although SPR and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, SPR and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In the PUCN order for Dockets 05-10024 and 05-10025, dated February 28, 2006, a dividend restriction was instituted for both utilities. Under this restriction, the combined amount that NPC and SPPC may pay to SPR each year is limited to the actual cash necessary to service SPR’s debt for the year. This restriction will expire when the Utilities’ senior secured debt is rated investment grade by two of the three credit rating agencies. See “Credit Ratings” below for discussion of current ratings.

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 Note 9, Debt Covenant and Other Restrictions in the Condensed Notes to Consolidated Financial Statements in this report and in Note 8, Debt Covenant Restrictions in the Notes to Consolidated Financial Statements in the 2006 Form 10-K.

As of March 31, 2007, 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, 2007, NPC had paid $13.5 million in dividends to SPR and SPPC had paid $6.7 million in dividends to SPR.

Credit Ratings

SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations: Standard & Poor’s (S&P), Moody’s Investors Service, Inc. (Moody’s), Fitch Ratings Ltd. (Fitch), and Dominion Bond Rating Service (DBRS). As of May 4, 2007 the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPR	Sr. Unsecured Debt	BB (low)	BB-	B1	B
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	B
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+

* Ratings are investment grade

In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to SPR, NPC and SPPC. The ratings for the senior secured debt of NPC and SPPC are BBB (low), which is the minimum level for investment grade. The rating assigned to SPR’s senior notes is BB (low), which is non-investment grade. DBRS’s trend for all three companies is Stable.

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At the time of the PUCN order for Dockets 05-10024 and 05-10025, (see Dividends from Subsidiaries, above) SPR and the two Utilities were only rated by S&P, Moody’s and Fitch. The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies, but did not specify which rating agencies. It is not clear what effect the DBRS rating will have on the PUCN dividend restriction.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Financial Covenants

Nevada Power Company and Sierra Pacific Power Company

Each of NPC's $600 million Second Amended and Restated Revolving Credit Agreement and SPPC's $350 million Amended and Restated Revolving Credit Agreement, dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires that the Utility 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 the Utility 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, 2007, both Utilities were in compliance with these covenants.

Limitations on Indebtedness

The terms of SPR’s $250 million 8.625% Senior Unsecured Notes due March 15, 2014, $74.2 million 7.803% Senior Unsecured Notes due 2012 and $225 million 6.75% Senior Unsecured Notes due 2017 restrict SPR and 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 and SPPC’s Integrated Resource Plan, as approved or amended under order by the PUCN.

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, 2007, SPR, NPC and SPPC would have been able to issue approximately $2.3 billion of additional indebtedness on a consolidated basis, assuming an interest rate of 7%, per the requirement stated in number 1 above.

Cross Default Provisions

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

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NEVADA POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended March 31, 2007, NPC recognized net income of approximately $4.6 million compared to a net loss of approximately $3.3 million for the same period in 2006.

During the three months ended March 31, 2007, NPC paid $13.5 million in dividends to SPR.

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

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of NPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every two years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended March 31,
	2007		Change from Prior Year %			2006
Operating Revenues:
Electric	$	418,165		9.7	%	$	381,275
Energy Costs:
Purchased power		95,594		-40.8	%		161,596
Fuel for power generation		164,085		82.7	%		89,822
Deferral of energy costs-net		26,932		750.4	%		3,167
	$	286,611		12.6	%	$	254,585
Gross Margin	$	131,554		3.8	%	$	126,690

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

Electric Operating Revenue

	Three Months Ended March 31,
					Change from
	2007		2006		Prior Year %
Residential	$	179,249	$	157,895		13.5	%
Commercial		95,903		87,936		9.1	%
Industrial		124,826		113,955		9.5	%
Retail revenues		399,978		359,786		11.2	%
Other		18,187		21,489		-15.4	%
Total Revenues	$	418,165	$	381,275		9.7	%
Retail sales in thousands of megawatt-hours (MWH)		4,194		4,002		4.8	%
Average retail revenue per MWH	$	95.37	$	89.90		6.1	%

NPC’s retail revenues increased for the three months ended March 31, 2007, as compared to the same period in 2006, due to increases in retail rates and customer growth. Retail rates increased as a result of NPC’s 2006 BTER update and Deferred Energy Case which became effective May 2006 and August 2006, respectively. For details see Management’s Discussion and Analysis, Regulatory Proceedings in the 2006 Form 10-K. Also contributing to the increase in revenues was an increase in residential, commercial and industrial customers by 3.3%, 4.9% and 6.4%, respectively.

Based on NPC’s projected customer forecast, NPC expects retail electric customers in the Clark County area to continue to grow in 2007, although at a slower pace than in 2006. In November 2006, NPC filed its GRC with the PUCN requesting an overall rate increase. For further discussion on NPC’s GRC, see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements.

Electric Operating Revenues - Other decreased for the three months ended March 31, 2007, compared to the same period in 2006, primarily due to revenues associated with Mohave which have been reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on Mohave refer to Commitments and Contingencies in the Condensed Notes to Financial Statements.

Purchased Power

	Three Months Ended March 31,
	2007		2006		Change from Prior Year %
Purchased Power	$	95,594	$	161,596		-40.8	%
Purchased Power in thousands of MWhs		1,183		2,300		-48.6	%
Average cost per MWh of Purchased Power	$	80.81	$	70.26		15.0	%

NPC’s purchased power costs and MWh decreased for the three months ended March 31, 2007 compared to the same period in 2006 primarily due to a decrease in volume. Volume decreased as a result of NPC’s increased reliance on internal generation, which was more economical than purchased power. The average cost per MWh hour increased primarily due to fixed capacity charges and a decrease in volume. Also contributing to the increase, in the average cost per MWh, was an increase in the cost of hedging instruments, partially offset by a decrease in energy costs.

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Fuel For Power Generation

	Three Months Ended March 31,
	2007		2006		Change from Prior Year %
Fuel for Power Generation	$	164,085	$	89,822		82.7	%
Thousands of MWhs generated		3,378		1,929		75.1	%
Average cost per MWh of Generated Power	$	48.58	$	46.56		4.3	%

Fuel for power generation increased for the three months ended March 2007, as compared to the same time period in 2006, primarily due to an increase in volume. The increase in volume was due to an increase in demand in NPC’s total system and the increased reliance on internal generation with the addition of Silverhawk in January 2006 and Lenzie Block 1 and 2 in February and April 2006, respectively. NPC relied more on internal generation as it was more economical than the purchase of power.

Average cost per MWh of generation increased primarily due to the mix of fuel used in the three months ended March 31, 2007, as compared to 2006, and due to the cost of hedging instruments, which was partially offset by lower natural gas prices. Due to the increases in volumes discussed above, NPC was required to use more of its natural gas generating units to meet demands. In 2007, approximately 72% of the MWhs generated required natural gas and 28% required coal, whereas in 2006, the mix was approximately 51% natural gas and 49% coal. The cost of natural gas is significantly higher than the cost of coal.

Deferred Energy Costs - Net

	Three Months Ended March 31,
	2007		2006		Change from Prior Year %
Deferred energy costs - net	$	26,932	$	3,167		N/A

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, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended March 31, 2007 and 2006 include amortization of deferred energy costs of $24.1 million and $21.3 million, respectively; and an over-collection of amounts recoverable in rates of $2.8 million in 2007, compared to an under-collection of $18.1 million in 2006.

Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended March 31,
	2007		2006		Change from Prior Year %
Allowance for other funds used during construction	$	3,098	$	5,429		-42. 9	%
Allowance for borrowed funds used during construction	$	2,550	$	5,372		-52. 5	%
	$	5,648	$	10,801		-47. 7	%

AFUDC decreased for the three months ended March 31, 2007, compared to the same period in 2006, due to the construction of Lenzie Blocks 1 and 2 and Harry Allen Unit in 2006. Lenzie Block 1 and 2 were completed in January and April 2006, respectively and Harry Allen was completed in May 2006

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Other (Income) and Expenses

	Three Months Ended March 31,
	2007			2006			Change from Prior Year %
Other operating expense	$	50,839		$	54,133			-6.1	%
Maintenance expense	$	17,464		$	14,157			23.4	%
Depreciation and amortization	$	35,761		$	34,237			4. 5	%
Interest charges on long-term debt	$	39,706		$	42,739			-7.1	%
Interest charges-other	$	6,836		$	3,827			78.6	%
Interest accrued on deferred energy	$	(3,849	)	$	(6,783	)		-43.3	%
Carrying charge for Lenzie	$	(10,082	)	$	(4,031	)		150.1	%
Reinstated interest on deferred energy	$	(11,076	)	$	-			N/A
Other income	$	(5,121	)	$	(4,366	)		17.3	%
Other expense	$	2,042		$	1,965			3.9	%

Other operating expense decreased for the three months ended March 31, 2007, compared to the same period in 2006, primarily due to the reversal of a reserve established for Enron legal fees. In March 2007, the PUCN granted recovery of these expenses, see Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion. In the three months ended March 31, 2006, NPC incurred increased consulting costs as compared to the same period in 2007.

Maintenance expense increased for the three months ended March 31, 2007, compared to the same period in 2006, mainly due to maintenance costs for the Lenzie Units, which were place in service in January 2006 and April 2006, for Unit 1 and Unit 2, respectively, and the timing of outages at Reid Gardner (forced outages in 2007 and deferred maintenance in 2006), partially offset by scheduled and forced outages at Clark Station in 2006.

Depreciation and amortization expenses increased during the three months ended March 31, 2007, compared to the same period in 2006, primarily as a result of increases to plant-in-service due to the purchase of Silverhawk and the completion of Harry Allen Unit IV in 2006.

Interest charges on Long-Term Debt decreased for the three months ended March 31, 2007, as compared to the same period in 2006, due primarily to various re-financings of debt in 2006 at lower interest rates and a decrease in the use of the Revolving Credit Facility in the first quarter of 2007. In the first quarter of 2006, the Revolving Credit Facility was used primarily to fund capital expenditures. Interest expense for the Revolving Credit Facility was approximately $1.1 million for the three months ended March 31, 2007 compared to $3.5 million for the same period in the prior year. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2006 10-K for additional information regarding long-term debt.

Interest charges-other increased for the three months ended March 31, 2007, as compared to the same period in 2006, due to higher amortization costs related to new debt issues, as well as additional interest associated with customer transmission deposits and redemptions in 2006.

Interest accrued on deferred energy costs decreased for the three months ended March 31, 2007, as compared to the same period in 2006, due to lower deferred energy balances compared to the same period in 2006. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Carrying charges for Lenzie represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. Carrying charges increased for the three months ended March 31, 2007, as compared to the same period in 2006, due to the timing of commercial operation of the Units. Lenzie Unit 1 and 2 of this station were commercially operable in January 2006 and April 2006. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for discussion of the accounting for the carrying charge for Lenzie.

Reinstated interest on deferred energy represents the carrying charges which were previously expensed as a result of the PUCN’s decision on NPC’s 2001 Deferred Energy Case. In March 2007, PUCN approved a settlement agreement allowing NPC to recover past carrying charges.

Other income increased during the three months ended March 31, 2007, as compared to the same period in 2006, due to higher interest income, partially offset by the expiration of the amortization of gains associated with the disposition of property.

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Other expense increased during the three months ended March 31, 2007, as compared to the same period in 2006, due to several items, each of which is not materially significant.

ANALYSIS OF CASH FLOWS

NPC’s cash flows increased during the three months ended March 31, 2007, compared to the same period in 2006, due to an increase in cash from operations and a decrease in cash used in investing activities, offset by a reduction in cash from financing activities.

Cash flows from operating activities increased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to increased rates which affected the following:

·   increases in the collection of Accounts Receivables; and

·   a BTER rate which more accurately matched purchased power costs with amounts collected from customers.

Also contributing to the increase in cash flows from operating activities was a decrease in payments made to suppliers, due to the timing of payments and the net settlement with Enron in 2006 and payments for option premiums in 2006.

Cash flows from investing activities decreased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to the purchase of the Silverhawk Generating Station and completion of the construction of the Lenzie Generating Station in 2006.

Cash flows from financing activities decreased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to the purchase of Silverhawk Generating Station and construction of the Lenzie Generating Station which required significant amounts of capital.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows are electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on NPC’s outstanding indebtedness.

Available Liquidity as of March 31, 2007 (in millions)
Cash and Cash Equivalents	$	75.6
Balance available on Revolving Credit Facility(1)		431.7
	$	507.3

¹ As of May 4, 2007, NPC had approximately $411.8 million available under its revolving credit facility.

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

During the three months ended March 31, 2007, there were no material changes to the contractual obligations described in NPC’s 2006 Form 10-K, except for construction contracts entered into in January 2007 related to NPC’s peaking units at Clark Station for approximately $350.6 million.

Factors Affecting Liquidity

Financial Covenants

NPC's $600 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and amended in April 2006, 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

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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, 2007, NPC was in compliance with these covenants.

Limitations on Indebtedness

Certain factors impact NPC’s ability to issue debt:

1.   Financing Authority from the PUCN: In February 2006, NPC received PUCN authorization to enter into financings of $1.78 billion, which amount included $600 million for the revolving credit facility (described above). NPC has issued approximately $100 million of the new debt authorized under the PUCN Order. NPC’s only remaining authority under this PUCN Order allows NPC to refinance its existing debt and to use its $600 million revolving credit facility.

2.   Limits on Bondable Property: To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the General and Refunding Mortgage Indenture. As of March 31, 2007, NPC had the capacity to issue $719 million of General and Refunding Mortgage Securities.

3.   Financial Covenants in its financing agreements.

The terms of certain SPR debt further prohibit NPC and SPPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of NPC’s Series G Notes, which mature in 2013, NPC’s Series I Notes, which mature in 2012, NPC’s Series L Notes, which mature in 2015, and NPC's Second Amended and Restated Revolving Credit Facility restrict NPC from incurring any additional indebtedness unless certain covenants are satisfied. See Note 8, Debt Covenant Restrictions, of the Notes to Financial Statements in the 2006 Form 10-K. If NPC’s Series G Notes, Series I Notes, or the Series L Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of securities remains investment grade.

As of March 31, 2007, the financial covenants under the revolving credit facility, which are more restrictive than the Series G, I and L Notes restrictions, would allow NPC to issue up to $2.1 billion of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, of $2.3 billion as of March 31, 2007. However, since NPC currently has no PUCN authority to issue new debt, NPC is limited to borrowing under its credit facility. As of May 4, 2007, the balance available under the credit facility is $411.8 million.

Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $2.3 billion, depending on the Utilities’ combined usage of their respective revolving credit facilities at the time of the covenant calculation.

Limitations on Ability to Issue General and Refunding Mortgage Bonds

NPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of March 31, 2007, $2.7 billion of NPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (3) above under “Limitations on Indebtedness” additional securities may be issued under the General and Refunding Mortgage Indenture as of March 31, 2007. That amount is determined on the basis of:

1.   70% of net utility property additions;

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

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

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

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Credit Ratings

NPC is rated by four Nationally Recognized Statistical Rating Organizations: S&P, Moody’s, Fitch and DBRS. As of May 4, 2007 the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	B

* Ratings are investment grade

In February 2007, Dominion Bond Rating Service (DBRS), who had not previously issued ratings on the companies, assigned new ratings to NPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment grade. DBRS’s trend for the company is Stable.

At the time of the PUCN order for Dockets 05-10024 and 05-10025, (see Dividends from Subsidiaries, SPR Liquidity, above) SPR and the two Utilities were only rated by S&P, Moody’s and Fitch. The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies, but did not specify which rating agencies. It is not clear what effect, if any, the DBRS rating will have on the PUCN dividend restriction.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Cross Default Provisions

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

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

During the three months ended March 31, 2007, SPPC recognized earnings applicable to common stock of approximately $22.0 million compared to $12.3 million for the same period in 2006.

During the three months ended March 31, 2007, SPPC paid $6.7 million in dividends to SPR.

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.

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every two years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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

	Three Months Ended March 31,
	2007			Change from Prior Year			2006
Operating Revenues:
Electric	$	252,879			5.9	%	$	238,772
Gas		85,120			-1.9	%		86,725
	$	337,999			3.8	%	$	325,497
Energy Costs:
Purchased power	$	83,310			-9.6	%	$	92,148
Fuel for power generation		64,069			20.2	%		53,287
Gas purchased for resale		71,646			6.3	%		67,396
Deferral of energy costs-electric-net		13,861			1431.6	%		905
Deferral of energy costs-gas-net		(1,945	)		-141.1	%		4,731
	$	230,941			5.7	%	$	218,467
Energy Costs by Segment:
Electric	$	161,240			10.2	%	$	146,340
Gas		69,701			-3.4	%		72,127
	$	230,941			5.7	%	$	218,467
Gross Margin by Segment:
Electric	$	91,639			-0.9	%	$	92,432
Gas		15,419			5.6	%		14,598
	$	107,058			0.0	%	$	107,030

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

Electric Operating Revenue

	Three Months Ended March 31,
	2007		2006		Change from Prior year %
Electric Operating Revenues:
Residential	$	88,009	$	82,363		6.9	%
Commercial		87,000		81,834		6.3	%
Industrial		70,441		66,360		6.1	%
Retail revenues		245,450		230,557		6.5	%
Other		7,429		8,215		-9.6	%
Total Revenues	$	252,879	$	238,772		5.9	%
Retail sales in thousands
Mwh		2,150		2,069		3.9	%
Average retail revenues per Mwh	$	114.16	$	111.43		2.4	%

SPPC’s retail revenues increased for the three months ended March 31, 2007 as compared to the same period in the prior year primarily due to customer growth and increases in retail rates. The number of residential, commercial, and industrial customers increased (2.2%, 4.1%, and 3.4% respectively). Retail rates increased as a result of SPPC’s various general, energy, and deferred energy cases. For details see Management’s Discussion and Analysis, Regulatory Proceedings in the 2006 Form 10-K.

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The decrease in Electric Operating Revenues - Other for the three month period ended March 31, 2007 compared to the same period in 2006 was primarily due to a decrease in charges related to the departure of Barrick Gold from SPPC’s system.

Gas Operating Revenues

	Three Months Ended March 31,
	2007		2006		Change from Prior year %
Gas Operating Revenues:
Residential	$	47,712	$	49,289		-3.2	%
Commercial		23,348		22,743		2.7	%
Industrial		7,299		7,751		-5.8	%
Retail revenues		78,359		79,783		-1.8	%
Wholesale		5,915		6,149		-3.8	%
Miscellaneous		846		793		6.7	%
Total Revenues	$	85,120	$	86,725		-1.9	%
Retail sales in thousands
of decatherms		6,288		6,340		-0.8	%
Average retail revenues per decatherm	$	12.46	$	12.58		-1.0	%

SPPC’s retail gas revenues decreased for the three months ended March 31, 2007 as compared to the same period in 2006 primarily due to warmer temperatures during 2007 and decreases in retail customer rates. Retail rates decreased as a result of SPPC’s Gas GRC and 2006 Natural Gas and Propane Deferred Rate Case and BTER update. For details see Management’s Discussion and Analysis, Regulatory Proceedings in the 2006 Form 10-K. Partially offsetting these decreases was an increase in retail customers of 3.8%.

Purchased Power

	Three Months Ended March 31,
					Change from
	2007		2006		Prior Year %
Purchased Power:	$	83,310	$	92,148		-9.6	%
Purchased Power in thousands of MWhs		1,330		1,316		1.1	%
Average cost per MWh of Purchased Power	$	62.64	$	70.02		-10.6	%

 Purchased power costs decreased for the three months ended March 31, 2007 as compared to the same period in 2006 primarily due to decreases in natural gas prices which are reflected in the cost of purchased power. In the three months ended March 31, 2006, natural gas prices were higher compared to the same period in 2007 as a result of the 2005 hurricanes in the Southern United States.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2007		2006		Prior Year %
Fuel for Power Generation	$	64,069	$	53,287		20.2	%
Thousands of MWh generated		953		923		3.3	%
Average fuel cost per MWh
of Generated Power	$	67.23	$	57.73		16.5	%

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 Fuel for power generation increased for the three months ended March 31, 2007, as compared to the same period in 2006. The increase in fuel for generation costs was primarily due to the cost of hedging instruments in the three months ended March 31, 2007. The average cost per MWh increased for the three months ended March 31, 2007 as compared to the same period in 2006 primarily due to outages at Valmy and the increase in the cost of hedging instruments, partially offset by a decrease in natural gas costs. The outages at the coal-fired Valmy facility placed a greater reliance on the less cost-effective natural gas fired Tracy generation plant which increased the average fuel cost per MWh.

Gas Purchased for Resale

	Three Months Ended March 31,
					Change from
	2007		2006		Prior Year %
Gas Purchased for Resale	$	71,646	$	67,396		6.3	%
Gas Purchased for Resale
(in thousands of decatherms)		7,473		7,457		0.2	%
Average cost per decatherm	$	9.59	$	9.04		6.1	%

The cost of gas purchased for resale and average cost per decatherm increased for the three months ended March 31, 2007 as compared to the same period in 2006. The increase in cost is primarily due to the impact of the settlement of hedging instruments in the three months ended March 31, 2007. In addition, in the same period 2006, SPPC settled hedging transaction which resulted in a decrease in gas purchased for resale costs.

Deferred Energy Costs

	Three Months Ended March 31,
	2007			2006		Change from Prior Year %
Deferred energy costs - electric - net	$	13,861		$	905		N/A
Deferred energy costs - gas - net		(1,945	)		4,731		N/A
Total	$	11,916		$	5,636

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, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Deferred energy costs - electric - net for the three months ended March 31, 2007 and 2006 reflect amortization of deferred energy costs of $12.1 million and $11.3 million, respectively; and an over-collection of amounts recoverable in rates of $1.8 million in 2007 as opposed to an under-collection of $10.4 million.

Deferred energy costs - gas - net for the three months ended March 31, 2007 and 2006 reflect amortization of deferred energy costs of $0.5 million and $3.0 million, respectively; and an under-collection of amounts recoverable in rates in 2007 of $2.4 million as opposed to an over-collection of $1.7 million in 2006.

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Allowance for Funds Used During Construction (AFUDC)

	Three Months Ended March 31,
	2007		2006		Change from Prior Year %
Allowance for other funds
used during construction	$	3,469	$	703		393. 5	%
Allowance for borrowed funds						341. 9	%
used during construction		2,784		630		369. 1	%
	$	6,253	$	1,333

AFUDC increased for the three months ended March 31, 2007 compared to the same period in 2006 due to an increase in Construction Work-In-Progress (CWIP) associated with the expansion of the Tracy Generating Station.

Other (Income) and Expense

	Three Months Ended March 31,
	2007			2006			Change from Prior Year %
Other operating expense	$	32,848		$	34,175			-3.9	%
Maintenance expense	$	6,281		$	7,773			-19.2	%
Depreciation and amortization	$	20,472		$	23,224			-11. 9	%
Interest charges on long-term debt	$	16,108		$	17,690			-8.9	%
Interest charges-other	$	1,459		$	1,096			33.1	%
Interest accrued on deferred energy	$	(765	)	$	(1,933	)		-60.4	%
Other income	$	(1,831	)	$	(2,148	)		-14.8	%
Other expense	$	2,014		$	2,524			-20.2	%

Other operating expense decreased for the three months ended March 31, 2007 compared to the same period in 2006 primarily due to higher allocation of administrative and general costs to capital projects as well as a decrease in consulting services.

Maintenance expense decreased for the three-month period ended March 31, 2007 compared to the same period in 2006 due to planned maintenance at Tracy during the first quarter of 2006 and economic shutdown of Tracy Units 1 and 2 during the first quarter of 2007.

Depreciation and amortization expenses decreased for the three months ended March 31, 2007 compared to the same period in 2006 due to the change in depreciation rates as ordered by PUCN in SPPC’s General Electric and Gas Rate Cases.

Interest charges on long-term debt for the three months ended March 31, 2007 decreased from 2006 due primarily to the refinancing of $268 million of tax exempt debt from fixed to variable rate in November 2006, and debt redemptions in 2006 of $188 million. These refinancing and redemptions were partially offset by the issue of $300 million Series M notes in March 2006. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2006 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q.

Interest charges-other for the three months ended March 31, 2007 increased compared to the same period in 2006 due to higher amortization costs related to new debt issues and redemptions in 2006.

Interest accrued on deferred energy costs decreased for the three months ended March 31, 2007 due to lower deferred energy balances compared to the same period in 2006. See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income decreased during the three months ended March 31, 2007, when compared to the same period in 2006, due primarily to the expiration of the amortization of gains associated with the disposition of property.

Other expense decreased during the three months ended March 31, 2007, when compared to the same period in 2006, due primarily to higher advertising and pension costs in 2006.

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ANALYSIS OF CASH FLOWS

Cash decreased during the three months ended March 31, 2007, when compared to the same period in 2006, due to an increase in cash used in investing activities and a reduction in cash from financing activities, partially offset by an increase in cash from operations.

Cash flows from investing activities increased during the three months ended March 31, 2007 compared to the same period in 2006 primarily due to construction costs associated with the expansion at the Tracy Generating Station.

Cash flows from financing activities decreased during the three months ended March 31, 2007, compared to the same period in 2006, primarily due to a reduction in the issuance of debt and the use of the revolving credit facility which were used to refinance debt during 2006.

Cash flows from operating activities increased during the three months ended March 31, 2007 compared to the same period in 2006 primarily due to an increase in the BTER rate, which more accurately matched purchased power and fuel for generation costs, and the net settlement with Enron in 2006. Partially offsetting these amounts was the settlement of inter-company tax receivables in 2006.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows are electric and gas revenues, including the recovery of previously deferred energy and gas costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on SPPC’s outstanding indebtedness.

Available Liquidity as of March 31, 2007 (in millions)
Cash and Cash Equivalents	$	58.9
Balance available on Revolving Credit Facility(1)		308.2
	$	367.1

(1)   As of May 4, 2007, SPPC had approximately $307.4 million available under it's revolving credit facility.  Additionally, if necessary, SPPC has the ability to issue additional debt, as discussed under Limitations on Indebtedness.

SPPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy. However, to fund capital requirements, as discussed in the 2006 Form 10-K, SPPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and the issuance of long-term debt, preferred securities, and/or capital contributions from SPR.

During the three months ended March 31, 2007, there were no material changes to the contractual obligations described in SPPC’s 2006 Form 10-K except for certain financing transactions as discussed below. 

Financing Transactions

Washoe County Water Facilities Refunding Revenue Bonds

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

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

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

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

Factors Affecting Liquidity

Financial Covenants

SPPC's $350 million Amended and Restated Revolving Credit Agreement, dated November 2005, and amended in April 2006, 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, 2007, SPPC was in compliance with these covenants.

Limitations on Indebtedness

Certain factors impact SPPC’s ability to issue debt:

1.   Financing Authority from the PUCN: In February 2006, SPPC received PUCN authorization to enter into financings of $1.36 billion which amount includes $350 million for the revolving credit facility (described above). SPPC has issued approximately $21 million of the new debt authorized in the PUCN Order. SPPC’s remaining authority under this PUCN Order allows SPPC to use its $350 million revolving credit facility, to issue $349 million in new debt and to refinance existing debt as specified in the order.

2.   Limits on Bondable Property: To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the General and Refunding Mortgage Indenture. As of March 31, 2007, SPPC has the capacity to issue $363 million of General and Refunding Mortgage Securities.

3.   Financial Covenants in its financing agreements.

The terms of certain SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of SPPC’s Series H Notes and SPPC’s Amended and Restated Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless certain covenants are satisfied. See Note 8, Debt Covenant and Other Restrictions, of the Notes to Consolidated Financial Statements in the 2006 Form 10-K.

As of March 31, 2007, the financial covenants under the revolving credit facility, which are more restrictive than the Series H Notes restriction, would allow SPPC to issue up to $813 million of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, at $2.3 billion as of March 31, 2007. Therefore, SPPC would not be materially limited by SPR’s cap on additional indebtedness.

Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $2.3 billion, depending on the Utilities’ combined usage of their revolving credit facilities at the time of the covenant calculation.

Limitations on Ability to Issue General and Refunding Mortgage Bonds

 SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of March 31, 2007, $1.4 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (3) above under “Limitations on Indebtedness” additional securities may be issued under the General and Refunding Mortgage Indenture as of March 31, 2007. That amount has been determined on the basis of:

1.   70% of net utility property additions;

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

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

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

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Credit Ratings

SPPC is rated by four Nationally Recognized Statistical Rating Organizations: S&P, Moody’s, Fitch and DBRS. As of May 4, 2007 the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Ba1	BB+

* Ratings are investment grade

In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to SPPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment grade. DBRS’s trend for the company is Stable.

At the time of the PUCN order for Dockets 05-10024 and 05-10025, (see SPR Liquidity - Dividends from Subsidiaries) SPR and the two Utilities were only rated by S&P, Moody’s and Fitch. The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies, but did not specify which rating agencies. It is not clear what effect, if any, the DBRS rating will have on the PUCN dividend restriction.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Cross Default Provisions

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

REGULATORY PROCEEDINGS (UTILITIES)

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

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

Under federal law, the Utilities 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.

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The Utilities are required to file annual DEAA cases, annual BTER Updates and biennial GRCs in Nevada. A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER update is to set rates to recover current energy costs. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital. As of March 31, 2007, NPC’s and SPPC’s balance sheets included approximately $476.7 million and $50.4 million, respectively, of deferred energy costs of which $415.2 and $23.8 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements.

Rate case applications filed in 2006 and 2007, 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 in Note3, Regulatory Actions, of the Condensed Notes to Financial Statements and the 2006 Form 10-K.

FERC Matters

FERC 890

On March 16, 2007, FERC issued Order 890 (Order), which amends the FERC’s open transmission access rules adopted in Order Nos. 888 and 889 and revises the FERC’s pro forma Open Access Transmission Tariff (OATT). The OATT revisions are scheduled to go into effect on July 13, 2007. The Utilities are preparing to make a filing with FERC by mid May, requesting modification of certain aspects of the OATT to ensure reservation of sufficient firm transmission import rights on their systems to comply with the Utilities’ PUCN-approved IRPs, which call for the use of short-term power purchases to meet summer and winter peak demands. The Utilities previously raised this issue in comments submitted during the Order 890 rulemaking process. In its Order, FERC invited the Utilities to propose changes to the OATT addressing their concerns. The Utilities are unable to predict whether the FERC will accept the proposed OATT changes they intend to file.

RECENT PRONOUNCEMENTS

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2007, SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

	Expected Maturity Date
																						Fair
	2007			2008			2009			2010			2011			Thereafter			Total			Value
Long-term Debt
SPR
Fixed Rate	$	-		$	-		$	-		$	-		$	-		$	549,209		$	549,209		$	576,400
Average Interest Rate		-			-			-			-			-			7.75	%		7.75	%
NPC
Fixed Rate	$	13		$	12		$	-		$	-		$	364,000		$	1,776,835		$	2,140,860		$	2,230,515
Average Interest Rate		8.17	%		8.17	%		-			-			8.14	%		6.58	%		6.85	%
Variable Rate	$	-		$	-		$	15,000		$	125,000		$	-		$	192,500		$	332,500		$	332,500
Average Interest Rate		-			-			3.81	%		6.22	%		-			3.66	%		4.63	%
SPPC
Fixed Rate	$	1,704		$	322,400		$	80,600		$	-		$	-		$	400,000		$	804,704		$	818,936
Average Interest Rate		6.40	%		7.99	%		5.01	%		-			-			6.06	%		6.73	%
Variable Rate	$	-		$	-		$	-		$	25,000		$	-		$	268,250		$	293,250		$	293,250
Average Interest Rate		-			-			-			6.20	%		-			3.56	%		3.78	%
Total Debt	$	1,717		$	322,412		$	95,600		$	150,000		$	364,000		$	3,186,794		$	4,120,523		$	4,251,601

Commodity Price Risk

See the 2006 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2006.

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 $62.0 million as of March 31, 2007, which increased from the $31.1 million balance at December 31, 2006. The increase from December 31, 2006 is primarily due to a $25 million exposure associated with a 285 MW summer 2007 tolling agreement executed by NPC in January 2007.

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, 2007, 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 2007 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

As of the date of this report, there have been no material changes with regard to administrative and judicial proceedings involving regulatory, environmental and other matters as disclosed in SPR’s, NPC’s and SPPC’s Annual Reports on Form 10-K for the year ended December 31, 2006, except as discussed below.

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

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. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power. The Utilities have since negotiated bilateral settlement agreements with all power suppliers that had termination claims for undelivered power against the Utilities. The Utilities were unable to reach settlement with other respondents.

 In June 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. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (July decision). The Utilities appealed the July decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. On May 3, 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed a petition for certiorari (Petition) with the U.S. Supreme Court seeking review of the Ninth Circuit decision. The Utilities cannot predict whether the U.S. Supreme Court will grant or deny the Petition.

Environmental

Nevada Power Company

Reid Gardner Station

As disclosed in prior filings, in June 2006 the Environmental Protection Agency (EPA) issued a Finding and Notice of Violation (NOV) related to monitoring, recordkeeping and emission exceedances at the Reid Gardner facility. In April, 2007 NPC lodged a Consent Decree in federal district court with NDEP, EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that will be required to resolve the alleged violations. Terms of the Consent Decree include a $1.1 million fine, of projects, of which NPC does not expect to be material for the Supplemental Environmental Project with the Clark County School District aimed at achieving increased energy efficiency and cost savings and the installation of emission reduction equipment at the facility. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in NPC’s 2006 IRP filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen. Capital expenditures are estimated at $84.2 million as approved by the PUCN, however, amounts may change depending on the procurement of material and services.

ITEM 1A RISK FACTORS

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in SPR’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2006.

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

None.

ITEM 5. OTHER INFORMATION

 On May 7, 2007, Glenn C. Christenson, recently retired executive vice president and chief financial officer of Station Casinos, Inc., was elected to SPR's board of directors, as well as NPC’s and SPPC’s board of directors.  Mr. Christenson will serve on the Audit Committee, Nominating and Governance Committee, and the Planning and Finance Committee. Mr. Christenson's term as an SPR director will run until SPR's 2008 annual meeting.

48

ITEM 6. EXHIBITS

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

Sierra Pacific Power Company:

10.1 Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007A).

10.2   Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007B).

10.3   Agreement, amended as of March 5, 2007, between Sierra Pacific Power Company and Local Union 1245 of the International Brotherhood of Electrical Workers.

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

            31.1 Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

            31.4 Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

                    31.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

                        32.1 Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

               32.4 Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

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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 under-signed thereunto duly authorized.

                                                                                          Sierra Pacific Resources

                                              (Registrant)

    Date: May 7, 2007                                                                                                          By: /s/ William D. Rogers 

                                                                                 William D. Rogers

                                                                            Chief Financial Officer

                                              (Principal Financial Officer)

         Date: May 7, 2007                                                                                                           By: /s/ John E. Brown 

                                                                               John E. Brown

                                                                            Controller

                                                                                (Principal Accounting Officer)

                                        Nevada Power Company

                                                                     (Registrant)

         Date: May 7, 2007                                                                                                           By: /s/ William D. Rogers 

                                                                                  William D. Rogers

                                                                             Chief Financial Officer

                                                                                                                                                          (Principal Financial Officer)

         Date: May 7, 2007                                                                                                           By: /s/ John E. Brown 

                                                                               John E. Brown

                                                                            Controller

                                                                               (Principal Accounting Officer)

                                                                                                                                                  Sierra Pacific Power Company

                                                                            (Registrant)

          Date: May 7, 2007                                                                                                          By: /s/ William D. Rogers 

                                                                                                                                                        William D. Rogers

                                                                             Chief Financial Officer

                                               (Principal Financial Officer)

           Date: May 7, 2007                                                                                                         By: /s/ John E. Brown 

                                                                                                                                                        John E. Brown

                                                                                                                                                        Controller

                                                                                                                                                         (Principal Accounting Officer)