SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

September 30, December 31,

2008
2007
ASSETS
Utility Plant at Original Cost:
Plant in service $ 9,278,831 $ 8,468,711
    Less accumulated provision for depreciation 2,607,546 2,526,379
6,671,285 5,942,332
    Construction work-in-progress 790,970 1,068,666
7,462,255 7,010,998

Investments and other property, net 31,037 31,061

Current Assets:
Cash and cash equivalents 229,145 129,140
  Accounts receivable less allowance for uncollectible accounts:
   2008- $33,823, 2007-$36,061 528,443 434,359
Deferred energy costs - electric (Note 1) 43,509 75,948
Materials, supplies and fuel, at average cost 130,164 117,483
Risk management assets (Note 5) 17,387 22,286
Deferred income taxes 82,951 43,295
Other 41,903 45,909
1,073,502 868,420
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1) 291,223 205,030
Regulatory tax asset 267,445 267,848
Regulatory asset for pension plans 185,295 133,984
Other regulatory assets 777,568 758,287
Risk management assets (Note 5) 8,893 12,429
Risk management regulatory assets - net (Note 5) 210,346 26,067
Unamortized debt issuance costs 64,494 65,218
Other 158,272 85,408
1,963,536 1,554,271
TOTAL ASSETS $ 10,530,330 $ 9,464,750
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $ 3,156,607 $ 2,996,575
Long-term debt 4,793,078 4,137,864
7,949,685 7,134,439
Current Liabilities:
Current maturities of long-term debt 9,794 110,285
Accounts payable 348,898 357,867
Accrued interest 75,970 69,485
Accrued salaries and benefits 38,664 35,020
Current income taxes payable - 3,544
Risk management liabilities (Note 5) 185,759 39,509
Accrued taxes 8,378 8,336
Deferred energy costs - electric (Note 1) 3,950 17,573
Deferred energy costs - gas (Note 1) 10,869 11,369
Other current liabilities 89,150 65,991
771,432 718,979
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes 982,987 852,630
Deferred investment tax credit 26,665 28,895
Regulatory tax liability 26,273 28,445
Customer advances for construction 89,108 100,125
Accrued retirement benefits 121,872 77,525
Risk management liabilities (Note 5) 35,201 7,369
Regulatory liabilities 326,518 304,026
Other 200,589 212,317
1,809,213 1,611,332
TOTAL CAPITALIZATION AND LIABILITIES $ 10,530,330 $ 9,464,750

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

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	10,455,344	$	10,358,843
Less accumulated provision for depreciation			2,714,889		2,659,219
			7,740,455		7,699,624
Construction work-in-progress			687,839		610,667
			8,428,294		8,310,291

Investments and other property, net			25,061		25,189

Current Assets:
Cash and cash equivalents			113,281		54,359
Accounts receivable less allowance for uncollectible accounts:
	2009 - $30,842, 2008 - $32,695		374,470		415,856
Deferred energy costs - electric (Note 3)			91,286		50,436
Materials, supplies and fuel, at average cost			124,311		125,391
Risk management assets (Note 5)			13,602		16,118
Current income taxes receivable			5,487		5,487
Deferred income taxes			76,817		49,996
Other			55,532		52,633
			854,786		770,276
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			154,248		231,027
Regulatory assets			1,504,203		1,415,436
Regulatory asset for pension plans			406,039		413,544
Risk management assets (Note 5)			6,694		9,959
Other			174,478		170,258
			2,245,662		2,240,224
TOTAL ASSETS		$	11,553,803	$	11,345,980

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,086,337	$	3,131,186
Long-term debt			5,485,643		5,266,982
			8,571,980		8,398,168
Current Liabilities:
Current maturities of long-term debt			8,885		9,291
Accounts payable			360,922		400,084
Accrued expenses			112,294		131,720
Risk management liabilities (Note 5)			412,519		313,846
Other			119,342		114,442
			1,013,962		969,383
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			936,550		920,481
Deferred investment tax credit			25,187		25,923
Accrued retirement benefits			276,636		288,841
Risk management liabilities (Note 5)			30,942		53,403
Regulatory liabilities			367,490		361,337
Other			331,056		328,444
			1,967,861		1,978,429
TOTAL CAPITALIZATION AND LIABILITIES		$	11,553,803	$	11,345,980

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

SIERRA  PACIFIC RESOURCES

CONSOLIDATED INCOME STATEMENTS

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

Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007

OPERATING REVENUES:
  Electric $ 1,098,744 $ 1,185,205 $ 2,624,832 $ 2,676,713
  Gas 19,379 20,839 137,125 137,337
  Other 8 6 19 325
1,118,131 1,206,050 2,761,976 2,814,375
OPERATING EXPENSES:
  Operation:
    Purchased power 383,329 410,467 828,635 851,396
    Fuel for power generation 332,872 238,180 825,105 658,392
    Gas purchased for resale 13,760 11,661 108,288 103,169
    Deferral of energy costs - electric - net (89,575 ) 66,660 (56,679 ) 193,954
    Deferral of energy costs - gas - net (725 ) 2,594 (2,296 ) 4,203
    Other 105,087 98,399 295,409 275,414
  Maintenance 20,337 23,308 64,931 77,686
  Depreciation and amortization 59,245 58,876 185,656 174,787
  Taxes:
    Income taxes 61,148 69,677 82,695 76,166
    Other than income 13,701 13,091 40,266 37,710
899,179 992,913 2,372,010 2,452,877
OPERATING INCOME 218,952 213,137 389,966 361,498

OTHER INCOME (EXPENSE):
  Allowance for other funds used during construction 7,865 9,214 32,935 22,393
  Interest accrued on deferred energy 2,349 4,633 4,042 13,020
  Carrying charge for Lenzie - - - 16,080
  Reinstated interest on deferred energy - - - 11,076
  Other income 6,583 4,605 24,787 18,293
  Other expense (3,007 ) (5,044 ) (10,804 ) (18,110 )
  Income taxes (4,263 ) (4,572 ) (16,451 ) (20,630 )
9,527 8,836 34,509 42,122
Total Income Before Interest Charges 228,479 221,973 424,475 403,620

INTEREST CHARGES:
  Long-term debt 75,483 69,686 215,826 204,681
  Other 8,391 7,626 23,092 23,625
  Allowance for borrowed funds used during construction (6,178 ) (7,561 ) (25,418 ) (18,269 )
77,696 69,751 213,500 210,037

NET INCOME APPLICABLE TO COMMON STOCK $ 150,783 $ 152,222 $ 210,975 $ 193,583

Amount per share basic and diluted (Note 7)
   Net Income applicable to common stock $ 0.64 $ 0.69 $ 0.90 $ 0.87

Weighted Average Shares of Common Stock Outstanding - basic 234,096,559 221,612,243 233,975,552 221,424,682
Weighted Average Shares of Common Stock Outstanding - diluted 234,655,132 221,968,802 234,499,269 221,783,424
Dividends Declared Per Common Share
$ 0.08 $ 0.08 $ 0.24 $ 0.08

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

~~Table of Contents~~

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended
September 30,
2008 2007
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net Income applicable to common stock $ 210,975 $ 193,583
  Adjustments to reconcile net income to net cash from operating activities:
     Depreciation and amortization 185,656 174,787
     Deferred taxes and deferred investment tax credit 172,425 103,598
     AFUDC (32,935 ) (22,393 )
     Amortization of deferred energy costs - electric 140,522 172,046
     Amortization of deferred energy costs - gas (983 ) 734
     Deferral of energy costs - electric (203,396 ) 11,900
     Deferral of energy costs - gas 483 3,749
     Carrying charge on Lenzie plant - (16,080 )
     Reinstated interest on deferred energy - (11,076 )
     Other, net 13,087 26,518
  Changes in certain assets and liabilities:
     Accounts receivable (139,755 ) (146,865 )
     Materials, supplies and fuel (12,682 ) (13,588 )
     Other current assets 4,005 1,982
     Accounts payable (33,712 ) 37,232
     Accrued retirement benefits (13,839 ) (92,291 )
     Other current liabilities 33,403 24,422
     Risk Management assets and liabilities (1,763 ) 11,805
     Other deferred assets (34,433 ) 7,964
     Other regulatory assets (50,702 ) (15,096 )
     Other liabilities (12,102 ) (9,872 )
Net Cash from Operating Activities 224,254 443,058

CASH FLOWS USED BY INVESTING ACTIVITIES:
     Additions to utility plant (excluding equity related to AFUDC) (671,918 ) (899,605 )
     Customer advances for construction (11,018 ) 4,749
     Contributions in aid of construction 57,437 41,243
     Investments and other property - net 4,312 2,928
Net Cash used by Investing Activities (621,187 ) (850,685 )

CASH FLOWS FROM FINANCING ACTIVITIES:
     Proceeds from issuance of long-term debt 1,420,002 1,201,354
     Retirement of long-term debt (871,987 ) (800,471 )
     Sale of Common Stock 5,195 4,525
     Proceeds from exercise of stock option �� - 5,112
     Dividends paid (56,272 ) (17,743 )
Net Cash from Financing Activities 496,938 392,777

Net Increase (Decrease) in Cash and Cash Equivalents 100,005 (14,850 )
Beginning Balance in Cash and Cash Equivalents 129,140 115,709
Ending Balance in Cash and Cash Equivalents $ 229,145 $ 100,859

Supplemental Disclosures of Cash Flow Information:
     Cash paid during period for:
       Interest $ 213,857 $ 193,549
       Income taxes $ 16,897 $ 9,727

The accompanying notes are an integral part of the financial statements

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amount)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008

OPERATING REVENUES:
Electric	$	674,267		$	719,450
Gas		80,993			85,594
Other		7			7
		755,267			805,051
OPERATING EXPENSES:
Operation:
Fuel for power generation		230,104			221,608
Purchased power		125,387			183,856
Gas purchased for resale		70,272			66,896
Deferral of energy costs - electric - net		49,986			54,282
Deferral of energy costs - gas – net		(4,351	)		2,203
Other		114,677			91,675
Maintenance		34,400			23,122
Depreciation and amortization		78,048			62,070
Taxes:
Income taxes (benefit)		(13,656	)		8,619
Other than income		14,647			13,907
		699,514			728,238
OPERATING INCOME		55,753			76,813

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,218			11,957
Interest accrued on deferred energy		1,180			1,236
Other income		5,058			13,672
Other expense		(5,578	)		(3,027	)
Income taxes		(2,242	)		(8,089	)
		4,636			15,749
Total Income Before Interest Charges		60,389			92,562

INTEREST CHARGES:
Long-term debt		78,557			69,955
Other		9,222			7,701
Allowance for borrowed funds used during construction		(5,146	)		(9,152	)
		82,633			68,504

NET INCOME (LOSS)	$	(22,244	)	$	24,058

Amount per share basic and diluted - (Note 7)
Net Income (Loss) per share – basic and diluted	$	(0.09	)	$	0.10

Weighted Average Shares of Common Stock Outstanding - basic		234,331,044			233,836,234
Weighted Average Shares of Common Stock Outstanding - diluted		234,331,044			234,321,972
Dividends Declared Per Share of Common Stock	$	0.10		$	0.08

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

~~Table of Contents~~

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	(22,244	)	$	24,058
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		78,048			62,070
Deferred taxes and deferred investment tax credit		5,264			9,482
AFUDC		(6,218	)		(11,957	)
Amortization of energy costs, net of deferrals		45,803			58,847
Other, net		16,836			(9,394	)
Changes in certain assets and liabilities:
Accounts receivable		23,909			59,799
Materials, supplies and fuel		1,080			7,289
Other current assets		(2,899	)		1,617
Accounts payable		(41,216	)		(16,128	)
Accrued retirement benefits		(12,205	)		4,537
Other current liabilities		(24,400	)		5,331
Risk management assets and liabilities		267			(352	)
Other deferred assets		(3,988	)		(5,925	)
Other regulatory assets		(11,251	)		(16,508	)
Other deferred liabilities		4,493			(10,859	)
Net Cash from Operating Activities		51,279			161,907

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(197,498	)		(225,465	)
Customer advances for construction		(3,260	)		(783	)
Contributions in aid of construction		17,104			32,475
Investments and other property – net		9			4,392
Net Cash used by Investing Activities		(183,645	)		(189,381	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		909,020			40,000
Retirement of long-term debt		(695,100	)		(4,364	)
Sale of Common Stock		818			2,253
Dividends paid		(23,450	)		(18,798	)
Net Cash from Financing Activities		191,288			19,091

Net Increase (Decrease) in Cash and Cash Equivalents		58,922			(8,383	)
Beginning Balance in Cash and Cash Equivalents		54,359			129,140
Ending Balance in Cash and Cash Equivalents	$	113,281		$	120,757

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	92,750		$	68,326
Income taxes	$	-		$	3,544

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

September 30,
December 31,

2008
2007
ASSETS
Utility Plant at Original Cost:
Plant in service $ 5,898,778 $ 5,571,492
    Less accumulated provision for depreciation 1,460,458 1,407,334
4,438,320 4,164,158
Construction work-in-progress 660,722 576,127
5,099,042 4,740,285

Investments and other property, net 19,662 19,544

Current Assets:
Cash and cash equivalents 177,734 37,001
Accounts receivable less allowance for uncollectible accounts:
2008- $31,462 , 2007-$30,392 396,035 274,242
Deferred energy costs - electric (Note 1) 43,509 75,948
Materials, supplies and fuel, at average cost 78,202 68,671
Risk management assets (Note 5) 12,844 16,078
Intercompany income taxes receivable 49,727 -
Deferred income taxes - 2,383
  Other 29,585 28,352
787,636 502,675
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1) 291,223 205,030
Regulatory tax asset 170,383 165,257
Regulatory asset for pension plans 102,509 86,909
Other regulatory assets 538,111 524,460
Risk management assets (Note 5) 6,502 9,069
Risk management regulatory assets - net (Note 5) 146,907 17,186
Unamortized debt issuance costs 36,865 36,551
Other 138,561 70,403
1,431,061 1,114,865
TOTAL ASSETS $ 7,337,401 $ 6,377,369
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 2,629,078 $ 2,376,740
Long-term debt 2,975,201 2,528,141
5,604,279 4,904,881
Current Liabilities:
Current maturities of long-term debt 8,656 8,642
Accounts payable 246,397 231,205
Accounts payable, affiliated companies 27,628 32,706
Accrued interest 54,539 41,920
Dividends declared - 10,907
Accrued salaries and benefits 20,188 16,881
Current income taxes payable - 3,544
Intercompany income taxes payable - 15,403
Deferred income taxes 6,224 -
Risk management liabilities (Note 5) 132,458 26,982
Accrued taxes 4,268 4,529
Other current liabilities 74,012 50,902
574,370 443,621
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes 691,955 585,168
Deferred investment tax credit 10,293 11,169
Regulatory tax liability 9,136 10,038
Customer advances for construction 45,939 58,890
Accrued retirement benefits 46,281 25,693
Risk management liabilities (Note 5) 22,571 5,116
Regulatory liabilities 175,376 168,381
  Other 157,201 164,412
1,158,752 1,028,867

TOTAL CAPITALIZATION AND LIABILITIES $ 7,337,401 $ 6,377,369

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

~~Table of Contents~~

NEVADA POWER COMPANY

CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
OPERATING REVENUES:
  Electric $ 826,825 $ 894,226 $ 1,866,220 $ 1,887,499

OPERATING EXPENSES:
  Operation:
    Purchased power 319,324 313,487 577,161 584,797
    Fuel for power generation 240,027 166,284 613,968 471,142
    Deferral of energy costs-net (80,191 ) 54,868 (44,107 ) 149,531
    Other 69,432 61,400 189,144 167,401
  Maintenance 12,469 16,360 42,727 54,143
  Depreciation and amortization 37,902 38,151 120,855 112,745
  Taxes:
    Income taxes 54,595 65,407 69,592 65,849
    Other than income 8,266 8,005 24,015 22,431
661,824 723,962 1,593,355 1,628,039
OPERATING INCOME 165,001 170,264 272,865 259,460

OTHER INCOME (EXPENSE):
  Allowance for other funds used during construction 6,543 4,701 21,093 11,046
  Interest accrued on deferred energy 2,803 4,573 5,681 11,849
  Carrying charge for Lenzie - - - 16,080
  Reinstated interest on deferred energy - - - 11,076
  Other income 4,116 2,315 12,970 10,345
  Other expense (2,028 ) (1,346 ) (5,045 ) (8,772 )
  Income taxes (3,828 ) (3,518 ) (11,350 ) (17,649 )
7,606 6,725 23,349 33,975
Total Income Before Interest Charges 172,607 176,989 296,214 293,435

INTEREST CHARGES:
  Long-term debt 46,662 41,955 129,283 123,029
  Other 6,737 5,876 17,952 18,315
  Allowance for borrowed funds used during construction (5,128 ) (3,936 ) (16,503 ) (9,189 )
48,271 43,895 130,732 132,155

NET INCOME $ 124,336 $ 133,094 $ 165,482 $ 161,280

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

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	6,954,369	$	6,884,033
Less accumulated provision for depreciation			1,538,558		1,500,502
			5,415,811		5,383,531
Construction work-in-progress			577,395		514,096
			5,993,206		5,897,627

Investments and other property, net			19,587		19,701

Current Assets:
Cash and cash equivalents			81,571		28,594
Accounts receivable less allowance for uncollectible accounts:
	2009 - $28,516 , 2008 - $30,621		225,572		238,379
Deferred energy costs - electric (Note 3)			91,286		50,436
Materials, supplies and fuel, at average cost			75,085		74,103
Risk management assets (Note 5)			10,278		11,724
Intercompany income taxes receivable			56,593		20,695
Deferred income taxes			-		2,682
Other			39,605		34,657
			579,990		461,270
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			154,248		231,027
Regulatory assets			1,051,137		971,354
Regulatory asset for pension plans			184,472		187,894
Risk management assets (Note 5)			5,336		7,346
Other			132,476		127,928
			1,527,669		1,525,549
TOTAL ASSETS		$	8,120,452	$	7,904,147

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,570,426	$	2,627,567
Long-term debt			3,596,840		3,385,106
			6,167,266		6,012,673
Current Liabilities:
Current maturities of long-term debt			8,885		8,691
Accounts payable			266,499		262,552
Accounts payable, affiliated companies			23,557		32,901
Accrued expenses			75,278		80,069
Deferred income taxes			12,772		-
Risk management liabilities (Note 5)			300,800		222,856
Other			68,498		72,762
			756,289		679,831
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			641,860		635,523
Deferred investment tax credit			9,711		10,001
Accrued retirement benefits			86,443		103,023
Risk management liabilities (Note 5)			23,281		35,241
Regulatory liabilities			193,336		188,709
Other			242,266		239,146
			1,196,897		1,211,643

TOTAL CAPITALIZATION AND LIABILITIES		$	8,120,452	$	7,904,147

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

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
OPERATING REVENUES:
Electric	$	436,529		$	469,172

OPERATING EXPENSES:
Operation:
Fuel for power generation		154,062			164,021
Purchased power		88,206			93,750
Deferral of energy costs-net		38,190			45,775
Other		70,193			57,095
Maintenance		27,534			16,650
Depreciation and amortization		52,363			40,630
Taxes:
Income taxes (benefit)		(18,547	)		2,132
Other than income		9,063			8,322
		421,064			428,375
OPERATING INCOME		15,465			40,797

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,621			6,858
Interest accrued on deferred energy		1,853			1,794
Other income		2,342			5,747
Other expense		(3,207	)		(1,361	)
Income taxes		(2,182	)		(4,391	)
		4,427			8,647
Total Income Before Interest Charges		19,892			49,444

INTEREST CHARGES:
Long-term debt		52,308			40,997
Other		7,297			5,831
Allowance for borrowed funds used during construction		(4,562	)		(5,355	)
		55,043			41,473

NET INCOME (LOSS)	$	(35,151	)	$	7,971

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

~~Table of Contents~~

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended
September 30,
2008 2007
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net Income $ 165,482 $ 161,280
  Adjustments to reconcile net income to net cash from or
  operating activities:
     Depreciation and amortization 120,855 112,745
     Deferred taxes and deferred investment tax credit 89,543 76,188
     AFUDC (21,093 ) (11,046 )
     Amortization of deferred energy costs 123,875 137,633
     Deferral of energy costs (173,522 ) 700
     Carrying charge on Lenzie plant - (16,080 )
     Reinstated interest on deferred energy - (11,076 )
     Other, net 2,659 3,077
  Changes in certain assets and liabilities:
     Accounts receivable (143,891 ) (180,404 )
     Materials, supplies and fuel (9,531 ) (7,189 )
     Other current assets (1,233 ) (4,680 )
     Accounts payable (21,048 ) 60,407
     Accrued retirement benefits (1,741 ) (49,794 )
     Other current liabilities 38,775 18,298
     Risk management assets and liabilities (989 ) 5,490
     Other deferred assets (35,291 ) 6,495
     Other regulatory assets (36,540 ) (11,538 )
     Other liabilities (8,113 ) 8,101
Net Cash from Operating Activities 88,197 298,607

CASH FLOWS USED BY INVESTING ACTIVITIES:
     Additions to utility plant (excluding equity related to AFUDC) (506,680 ) (573,921 )
     Customer advances for construction (12,951 ) 1,428
     Contributions in aid of construction 49,108 26,240
     Investments and other property - net 2,719 2,899
Net Cash used by Investing Activities (467,804 ) (543,354 )

CASH FLOWS FROM FINANCING ACTIVITIES:
     Proceeds from issuance of long-term debt 878,034 699,254
     Retirement of long-term debt (435,787 ) (422,780 )
     Additional investment by parent company 133,000 -
     Dividends paid (54,907 ) (23,472 )
Net Cash from Financing Activities 520,340 253,002

Net Increase in Cash and Cash Equivalents 140,733 8,255
Beginning Balance in Cash and Cash Equivalents 37,001 36,633
Ending Balance in Cash and Cash Equivalents $ 177,734 $ 44,888

Supplemental Disclosures of Cash Flow Information:
     Cash paid during period for:
       Interest $ 120,749 $ 115,047
       Income taxes $ 15,534 $ 6,760

The accompanying notes are an integral part of the financial statements

~~Table of Contents~~

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

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
Net Income (Loss)	$	(35,151	)	$	7,971
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		52,363			40,630
Deferred taxes and deferred investment tax credit		19,424			(14,443	)
AFUDC		(5,621	)		(6,858	)
Amortization of energy costs, net of deferrals		35,928			44,042
Other, net		10,269			(6,784	)
Changes in certain assets and liabilities:
Accounts receivable		(23,090	)		35,952
Materials, supplies and fuel		(982	)		4,623
Other current assets		(4,948	)		(590	)
Accounts payable		(17,299	)		(18,882	)
Accrued retirement benefits		(16,580	)		4,396
Other current liabilities		(9,056	)		13,716
Risk management assets and liabilities		(532	)		(553	)
Other deferred assets		(3,445	)		(8,834	)
Other regulatory assets		(10,572	)		(9,099	)
Other deferred liabilities		4,118			(8,426	)
Net Cash From (Used By) Operating Activities		(5,174	)		76,861

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(141,059	)		(156,302	)
Customer advances for construction		(2,101	)		(1,879	)
Contributions in aid of construction		15,603			28,057
Investments and other property – net		(4	)		2,821
Net Cash used by Investing Activities		(127,561	)		(127,303	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		748,404			40,000
Retirement of long-term debt		(540,692	)		(3,539	)
Additional investment by parent company		-			53,000
Dividends paid		(22,000	)		(24,907	)
Net Cash from Financing Activities		185,712			64,554

Net Increase (Decrease) in Cash and Cash Equivalents		52,977			14,112
Beginning Balance in Cash and Cash Equivalents		28,594			37,001
Ending Balance in Cash and Cash Equivalents	$	81,571		$	51,113

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	55,611		$	34,751
Income taxes	$	-		$	3,544

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

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

September 30, December 31,

2008
2007
ASSETS
Utility Plant at Original Cost:
Plant in service $ 3,380,053 $ 2,897,219
Less accumulated provision for depreciation 1,147,088 1,119,045
2,232,965 1,778,174
Construction work-in-progress 130,248 492,539
2,363,213 2,270,713

Investments and other property, net 424 570

Current Assets:
Cash and cash equivalents 29,343 23,807
Accounts receivable less allowance for uncollectible accounts:
2008 - $2,361; 2007 - $5,669 132,290 160,014
Materials, supplies and fuel, at average cost 51,941 48,799
Risk management assets (Note 5) 4,543 6,208
Intercompany income taxes receivable 39,202 -
Deferred income taxes 12,909 17,728
Other 11,767 17,255
281,995 273,811
Deferred Charges and Other Assets:
Regulatory tax asset 97,062 102,591
Regulatory asset for pension plans 76,239 43,778
Other regulatory assets 239,458 233,827
Risk management assets (Note 5) 2,391 3,360
Risk management regulatory assets - net (Note 5) 63,439 8,881
Unamortized debt issuance costs 19,843 19,976
Other 19,525 19,017
517,957 431,430
TOTAL ASSETS $ 3,163,589 $ 2,976,524
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity $ 1,015,690 $ 1,001,840
Long-term debt 1,292,867 1,084,550
2,308,557 2,086,390
Current Liabilities:
Current maturities of long-term debt 1,139 101,643
Accounts payable 75,695 94,722
Accounts payable, affiliated companies 15,629 19,288
Accrued interest 17,307 15,750
Dividends declared - 5,333
Accrued salaries and benefits 15,582 14,830
Intercompany income taxes payable - 2,479
Risk management liabilities (Note 5) 53,301 12,527
Accrued taxes 3,975 3,542
Deferred energy costs - electric (Note 1) 3,950 17,573
Deferred energy costs - gas (Note 1) 10,869 11,369
Other current liabilities 15,136 15,015
212,583 314,071
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes 291,028 267,801
Deferred investment tax credit 16,372 17,726
Regulatory tax liability 17,137 18,407
Customer advances for construction 43,169 41,235
Accrued retirement benefits 68,671 48,025
Risk management liabilities (Note 5) 12,630 2,253
Regulatory liabilities 151,142 135,645
Other 42,300 44,971
642,449 576,063
TOTAL CAPITALIZATION AND LIABILITIES $ 3,163,589 $ 2,976,524

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

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	3,500,975	$	3,474,810
Less accumulated provision for depreciation			1,176,331		1,158,717
			2,324,644		2,316,093
Construction work-in-progress			110,444		96,571
			2,435,088		2,412,664

Investments and other property, net			397		411

Current Assets:
Cash and cash equivalents			28,930		21,411
Accounts receivable less allowance for uncollectible accounts:
	2009 - $2,326; 2008 - $2,073		148,841		177,401
Materials, supplies and fuel, at average cost			49,167		51,252
Risk management assets (Note 5)			3,324		4,394
Intercompany income taxes receivable			64,591		64,932
Deferred income taxes			14,577		12,253
Other			15,803		17,631
			325,233		349,274
Deferred Charges and Other Assets:
Regulatory assets			453,066		444,082
Regulatory asset for pension plans			214,651		218,550
Risk management assets (Note 5)			1,358		2,613
Other			34,602		34,951
			703,677		700,196
TOTAL ASSETS		$	3,464,395	$	3,462,545

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	975,406	$	877,961
Long-term debt			1,402,964		1,395,987
			2,378,370		2,273,948
Current Liabilities:
Current maturities of long-term debt			-		600
Accounts payable			79,446		109,410
Accounts payable, affiliated companies			14,480		17,433
Accrued expenses			31,825		37,787
Dividends declared			-		96,800
Risk management liabilities (Note 5)			111,719		90,990
Other			50,844		41,680
			288,314		394,700
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			297,267		287,251
Deferred investment tax credit			15,476		15,922
Accrued retirement benefits			184,389		180,209
Risk management liabilities (Note 5)			7,661		18,162
Regulatory liabilities			174,154		172,628
Other			118,764		119,725
			797,711		793,897
TOTAL CAPITALIZATION AND LIABILITIES		$	3,464,395	$	3,462,545

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

910

~~Table of Contents~~

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
OPERATING REVENUES:
  Electric $ 271,919 $ 290,979 $ 758,612 $ 789,214
  Gas 19,379 20,839 137,125 137,337
291,298 311,818 895,737 926,551
OPERATING EXPENSES:
  Operation:
       Purchased power 64,005 96,980 251,474 266,599
       Fuel for power generation 92,845 71,896 211,137 187,250
       Gas purchased for resale 13,760 11,661 108,288 103,169
       Deferral of energy costs - electric - net (9,384 ) 11,792 (12,572 ) 44,423
       Deferral of energy costs - gas - net (725 ) 2,594 (2,296 ) 4,203
       Other 35,474 36,228 103,744 105,070
  Maintenance 7,868 6,948 22,204 23,543
  Depreciation and amortization 21,343 20,726 64,801 62,043
  Taxes:
       Income taxes 10,602 9,825 24,213 20,871
       Other than income 5,402 5,050 16,128 15,138
241,190 273,700 787,121 832,309
OPERATING INCOME 50,108 38,118 108,616 94,242

OTHER INCOME (EXPENSE):
  Allowance for other funds used during construction 1,322 4,513 11,842 11,347
  Interest accrued on deferred energy (454 ) 60 (1,639 ) 1,171
  Other income 2,367 1,865 11,331 6,707
  Other expense (749 ) (2,938 ) (5,430 ) (7,143 )
  Income taxes (683 ) (1,104 ) (5,210 ) (3,597 )
1,803 2,396 10,894 8,485
Total Income Before Interest Charges 51,911 40,514 119,510 102,727

INTEREST CHARGES:
     Long-term debt 18,635 17,096 55,975 49,746
     Other 1,407 1,491 4,398 4,533
     Allowance for borrowed funds used during construction (1,050 ) (3,625 ) (8,915 ) (9,080 )
18,992 14,962 51,458 45,199

NET INCOME $ 32,919 $ 25,552 $ 68,052 $ 57,528

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

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

	Three Months Ended
	March 31,
	2009			2008
OPERATING REVENUES:
Electric	$	237,738		$	250,278
Gas		80,993			85,594
		318,731			335,872
OPERATING EXPENSES:
Operation:
Fuel for power generation		76,042			57,587
Purchased power		37,181			90,106
Gas purchased for resale		70,272			66,896
Deferral of energy costs - electric – net		11,796			8,507
Deferral of energy costs - gas – net		(4,351	)		2,203
Other		44,015			33,505
Maintenance		6,866			6,472
Depreciation and amortization		25,685			21,440
Taxes:
Income taxes		9,078			9,659
Other than income		5,524			5,528
		282,108			301,903
OPERATING INCOME		36,623			33,969

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		597			5,099
Interest accrued on deferred energy		(673	)		(558	)
Other income		2,715			7,735
Other expense		(1,991	)		(1,800	)
Income taxes		(208	)		(3,574	)
		440			6,902
Total Income Before Interest Charges		37,063			40,871

INTEREST CHARGES:
Long-term debt		16,815			18,762
Other		1,696			1,622
Allowance for borrowed funds used during construction		(584	)		(3,797	)
		17,927			16,587

NET INCOME	$	19,136		$	24,284

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

~~Table of Contents~~

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended
September 30,
2008 2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 68,052 $ 57,528
  Adjustments to reconcile net income to net cash from operating activities:
     Depreciation and amortization 64,801 62,043
     Deferred taxes and deferred investment tax credit 28,472 (25,456 )
     AFUDC (11,842 ) (11,347 )
     Amortization of deferred energy costs - electric 16,647 34,413
     Amortization of deferred energy costs - gas (983 ) 734
     Deferral of energy costs - electric (29,874 ) 11,200
     Deferral of energy costs - gas 483 3,749
     Other, net 14,476 22,141
  Changes in certain assets and liabilities:
     Accounts receivable 4,152 33,257
     Materials, supplies and fuel (3,142 ) (6,399 )
     Other current assets 5,488 6,512
     Accounts payable (16,267 ) 3,310
     Accrued retirement benefits (15,789 ) (36,139 )
     Other current liabilities 2,864 13,940
     Risk management assets and liabilities (774 ) 6,315
     Other deferred assets 858 1,468
     Other regulatory assets (14,162 ) (3,558 )
     Other liabilities (2,142 ) (3,896 )
Net Cash from Operating Activities 111,318 169,815

CASH FLOWS USED BY INVESTING ACTIVITIES:
     Additions to utility plant (excluding equity related to AFUDC) (165,238 ) (325,684 )
     Customer advances for construction 1,933 3,321
     Contributions in aid of construction 8,329 15,004
     Investments and other property - net 1,597 25
Net Cash used by Investing Activities (153,379 ) (307,334 )

CASH FLOWS FROM FINANCING ACTIVITIES:
     Proceeds from issuance of long-term debt 541,968 502,100
     Retirement of long-term debt (436,038 ) (377,531 )
     Investment by parent company 20,000 -
     Dividends paid (78,333 ) (11,736 )
Net Cash from Financing Activities 47,597 112,833

Net Increase (Decrease) in Cash and Cash Equivalents 5,536 (24,686 )
Beginning Balance in Cash and Cash Equivalents 23,807 53,260
Ending Balance in Cash and Cash Equivalents $ 29,343 $ 28,574

Supplemental Disclosures of Cash Flow Information:
      Cash paid during period for:
       Interest $ 54,849 $ 38,854
       Income taxes $ 19 $ 64

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

~~Table of Contents~~

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

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	19,136		$	24,284
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		25,685			21,440
Deferred taxes and deferred investment tax credit		8,597			9,629
AFUDC		(597	)		(5,099	)
Amortization of energy costs, net of deferrals		9,875			14,805
Other, net		6,395			(1,310	)
Changes in certain assets and liabilities:
Accounts receivable		28,901			23,930
Materials, supplies and fuel		2,085			2,669
Other current assets		1,828			2,050
Accounts payable		(23,069	)		(500	)
Accrued retirement benefits		4,179			(643	)
Other current liabilities		(6,672	)		806
Risk management assets and liabilities		799			201
Other deferred assets		(543	)		2,909
Other regulatory assets		(679	)		(7,409	)
Other deferred liabilities		(75	)		(294	)
Net Cash from Operating Activities		75,845			87,468

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(56,439	)		(69,163	)
Customer advances for construction		(1,159	)		1,096
Contributions in aid of construction		1,501			4,418
Investments and other property - net		14			1,570
Net Cash used by Investing Activities		(56,083	)		(62,079	)

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		160,616			-
Retirement of long-term debt		(154,359	)		(771	)
Investment by parent company		90,300			20,000
Dividends paid		(108,800	)		(13,333	)
Net Cash From (Used By) Financing Activities		(12,243	)		5,896

Net Increase (Decrease) in Cash and Cash Equivalents		7,519			31,285
Beginning Balance in Cash and Cash Equivalents		21,411			23,807
Ending Balance in Cash and Cash Equivalents	$	28,930		$	55,092

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	20,755		$	15,688
Income taxes	$	-		$	-

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements ~~of Sierra Pacific Resources (SPR)~~ include the accounts of ~~SPR~~NV Energy, Inc. and its wholly-owned subsidiaries, Nevada Power Company, ~~(NPC) and~~ Sierra Pacific Power Company, ~~(SPPC) (collectively, the "Utilities"),~~Tuscarora Gas Pipeline Company, which was dissolved in 2008, Sierra ~~Gas Holding Company (SGHC)~~Pacific Communications, Lands of Sierra, Inc., 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.~~Gas Holding Company. All ~~significant~~intercompany balances and 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~~GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

In the opinion of the management of ~~SPR,~~NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain ~~all~~normal and recurring 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 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~~the 2008 Form ~~10-K and/or Form 10-K/A for the year ended December 31, 2007 (collectively, the “2007 Form 10-K”).~~10-K.

The results of operations and cash flows of ~~SPR,~~NVE, NPC and SPPC for the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, are not necessarily indicative of the results to be expected for the full year.

~~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 2007 Form 10-K, for additional information regarding deferred energy accounting by the Utilities.Reclassifications

Certain financial statement line items for prior periods have been re-grouped or reclassified to conform with current year presentation. The ~~following deferred energy costs were included in the consolidated balance sheets as~~re-groupings or reclassifications have not affected previously reported results of ~~September 30, 2008 (dollars in thousands):~~operations or common shareholders’ equity.

September 30, 2008
Description NPC Electric SPPC Electric SPPC Gas SPR Total

Unamortized balances approved for collection in current rates
as of January 1, 2008 $ 79,924 $ 13,257 $ (1,208 ) $ 91,973
Balances approved in 2008 DEAA(1)(2)
(44,424 ) (34,300 ) (10,174 ) (88,898 )
Cumulative Balance request in 2008 DEAA 35,500 (21,043 ) (11,382 ) 3,075
2008 amortization of approved balances (89,653 ) (13,098 ) 983 (101,768 )
2008 deferred energy costs not yet requested 175,056 29,267 (470 ) 203,853
Western Energy Crisis Rate Case (effective 6/07, 3 years) 46,711 - - 46,711
Reinstatement of deferred energy (effective 6/07, 10 years) 167,118 - - 167,118
Cumulative CPUC balance (3)
- 924 - 924
Total
$ 334,732 $ (3,950 ) $ (10,869 ) $ 319,913

Current Assets
Deferred energy costs – electric
$ 43,509 $ - $ - $ 43,509
Deferred Assets
Deferred energy costs - electric
291,223 - - 291,223
Current Liabilities
Deferred energy costs – electric
- (3,950 ) - (3,950 )
Deferred energy costs – gas
- - (10,869 ) (10,869 )
Total
$ 334,732 $ (3,950 ) $ (10,869 ) $ 319,913

~~(1)~~	~~Credit balances represent potential refunds to the Utilities’ customers.~~
~~(2)~~	~~DEAA is defined as Deferred Energy Accounting Adjustment.~~
~~(3)~~	~~CPUC is defined as California Public Utility Commission.~~

~~Table of Contents~~

Recent Pronouncements

SFAS 157-2

In February 2008, the FASB issued FSP 157-2, which deferred the effective date for certain portions of SFAS 157 related to nonrecurring measurements of nonfinancial assets and liabilities. SFAS 157-2 was effective for NVE and the Utilities beginning January 1, 2009. The adoption of SFAS 157-2 did not have a material impact on the consolidated financial statements.

SFAS 161

In March 2008, the FASB issued ~~Statement of Financial Accounting Standards No.~~SFAS 161, ~~Disclosures about Derivative Instruments~~ and ~~Hedging Activities an~~ amendment of ~~FASB Statement No.~~SFAS 133 ~~(“SFAS 161”)~~ which is effective for financial statements issued for fiscal years and interim ~~periods~~period beginning after November 15, 2008. The purpose of SFAS 161 is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. ~~The Utilities are currently evaluating the additional disclosure requirements but do not expect their disclosure to change significantly.~~

~~SFAS 157~~

~~Effective January 1, 2008, SPR~~NVE and the Utilities adopted ~~the provisions of~~ SFAS No. 157, Fair Value Measurements (“SFAS 157”) which defines fair value, establishes criteria when measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date,” or the “exit price.” Accordingly, an entity must now determine the fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. Additionally, SFAS No. 157 establishes a fair value hierarchy which gives precedence to fair value measurements calculated using observable inputs to those using unobservable inputs. The adoption of the provisions of SFAS No. 157 that became effective on161 beginning January 1, ~~2008 did not have a material impact on SPR or the Utilities financial condition and results of operations; however, it did require expanded disclosures with respect to fair value measurements.~~2009. See Note 5, ~~Derivative~~Derivatives and Hedging ~~Activities for the expanded disclosures.~~Activities.

FSP FAS 107-1 and APB 28-1

In ~~February 2008,~~April 2009, the ~~Financial Accounting Standards Board (FASB)~~FASB issued ~~Staff Position No. 157-2, which deferred~~FSP FAS 107-1 and APB 28-1, requiring disclosure of fair values of certain financial instruments in interim financial statements. The provisions of FSP 107-1 and APB 28-1 are effective for NVE and the ~~effective date for certain portions~~Utilities as of ~~SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. SPR~~June 30, 2009. NVE and the Utilities will be required to ~~adopt those provisions~~report on an interim basis substantially similar disclosure as reported in Note 7, Fair Value of Financial Instruments of the Notes to Financial Statements in the 2008 Form 10-K.

SFAS ~~No. 157 beginning January 1, 2009.~~ 157-4

In ~~October 2008,~~April 2009, the FASB issued ~~Staff Position No. 157-3 Determining~~FSP 157-4, which provides additional guidance on measuring the ~~Fair Value~~fair value of ~~a Financial Asset When the Market~~financial instruments when markets become inactive and quoted prices may reflect distressed transactions. The provisions of FSP 157-4 are effective for ~~That Asset is Not Active, (“FSP 157-3”) FSP157-3 is effective immediately. SPR~~NVE and the Utilities ~~considered~~as of June 30, 2009. NVE and the ~~guidance in FSP 157-3 and have determined that~~Utilities are currently evaluating the impact of the adoption ~~did~~of FSP 157-4, but do not expect the adoption to have a material impact on ~~the consolidated~~their financial statements.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as defined by SFAS ~~131, “Disclosure about Segments of an Enterprise and Related Information”);~~131) 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~~NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin. Gross margin, which the Utilities calculate as operating revenues less fuel, purchased power, and deferred energy costs, provides a measure of income available to support the other operating expenses of the Utilities. Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands).

Three Months Ended NPC SPPC SPPC SPPC SPR SPR
September 30, 2008 Electric Electric Gas Total Other Consolidated
Operating Revenues $ 826,825 $ 271,919 $ 19,379 $ 291,298 $ 8 $ 1,118,131

Energy Costs:
Purchased power 319,324 64,005 - 64,005 - 383,329
Fuel for power generation 240,027 92,845 - 92,845 - 332,872
Gas purchased for resale - - 13,760 13,760 - 13,760
Deferred energy costs - net (80,191 ) (9,384 ) (725 ) (10,109 ) - (90,300 )
479,160 147,466 13,035 160,501 - 639,661

Gross Margin $ 347,665 $ 124,453 $ 6,344 $ 130,797 $ 8 $ 478,470

Other 69,432 35,474 181 105,087
Maintenance 12,469 7,868 - 20,337
Depreciation and amortization 37,902 21,343 - 59,245
Taxes:
Income taxes 54,595 10,602 (4,049 ) 61,148
Other than income 8,266 5,402 33 13,701

Operating Income $ 165,001 $ 50,108 $ 3,843 $ 218,952


Three months ended	NPC			SPPC		SPPC			SPPC		NVE			NVE
March 31, 2009	Electric			Electric		Gas			Total		Other			Consolidated
Operating Revenues	$	436,529		$	237,738	$	80,993		$	318,731	$	7		$	755,267

Energy Costs:
Fuel for power generation		154,062			76,042		-			76,042		-			230,104
Purchased power		88,206			37,181		-			37,181		-			125,387
Gas purchased for resale		-			-		70,272			70,272		-			70,272
Deferred energy costs - net		38,190			11,796		(4,351	)		7,445		-			45,635
	$	280,458		$	125,019	$	65,921		$	190,940	$	-		$	471,398

Gross Margin	$	156,071		$	112,719	$	15,072		$	127,791	$	7		$	283,869

Other		70,193								44,015		469			114,677
Maintenance		27,534								6,866		-			34,400
Depreciation and amortization		52,363								25,685		-			78,048
Taxes:
Income taxes (benefit)		(18,547	)							9,078		(4,187	)		(13,656	)
Other than income		9,063								5,524		60			14,647

Operating Income	$	15,465							$	36,623	$	3,665		$	55,753

~~Table of Contents~~

Nine Months Ended NPC SPPC SPPC SPPC SPR SPR
September 30, 2008 Electric Electric Gas Total Other Consolidated
Operating Revenues $ 1,866,220 $ 758,612 $ 137,125 $ 895,737 $ 19 $ 2,761,976

Energy Costs:
Purchased power 577,161 251,474 - 251,474 - 828,635
Fuel for power generation 613,968 211,137 - 211,137 - 825,105
Gas purchased for resale - - 108,288 108,288 - 108,288
Deferred energy costs - net (44,107 ) (12,572 ) (2,296 ) (14,868 ) - (58,975 )
1,147,022 450,039 105,992 556,031 - 1,703,053

Gross Margin $ 719,198 $ 308,573 $ 31,133 $ 339,706 $ 19 $ 1,058,923

Other 189,144 103,744 2,521 295,409
Maintenance 42,727 22,204 - 64,931
Depreciation and amortization 120,855 64,801 - 185,656
Taxes:
Income taxes 69,592 24,213 (11,110 ) 82,695
Other than income 24,015 16,128 123 40,266

Operating Income $ 272,865 $ 108,616 $ 8,485 $ 389,966

Three Months Ended NPC SPPC SPPC SPPC SPR SPR
September 30, 2007 Electric Electric Gas Total Other Consolidated
Operating Revenues $ 894,226 $ 290,979 $ 20,839 $ 311,818 $ 6 $ 1,206,050

Energy Costs:
Purchased power 313,487 96,980 - 96,980 - 410,467
Fuel for power generation 166,284 71,896 - 71,896 - 238,180
Gas purchased for resale - - 11,661 11,661 - 11,661
Deferred energy costs - net 54,868 11,792 2,594 14,386 - 69,254
534,639 180,668 14,255 194,923 - 729,562

Gross Margin $ 359,587 $ 110,311 $ 6,584 $ 116,895 $ 6 $ 476,488

Other 61,400 36,228 771 98,399
Maintenance 16,360 6,948 - 23,308
Depreciation and amortization 38,151 20,726 (1 ) 58,876
Taxes:
Income taxes 65,407 9,825 (5,555 ) 69,677
Other than income 8,005 5,050 36 13,091

Operating Income $ 170,264 $ 38,118 $ 4,755 $ 213,137

~~Table of Contents~~

Nine Months Ended NPC SPPC SPPC SPPC SPR SPR
September 30, 2007 Electric Electric Gas Total Other Consolidated
Operating Revenues $ 1,887,499 $ 789,214 $ 137,337 $ 926,551 $ 325 $ 2,814,375

Energy Costs:
Purchased power 584,797 266,599 - 266,599 - 851,396
Fuel for power generation 471,142 187,250 - 187,250 - 658,392
Gas purchased for resale - - 103,169 103,169 - 103,169
Deferred energy costs - net 149,531 44,423 4,203 48,626 - 198,157
1,205,470 498,272 107,372 605,644 - 1,811,114

Gross Margin $ 682,029 $ 290,942 $ 29,965 $ 320,907 $ 325 $ 1,003,261

Other 167,401 105,070 2,943 275,414
Maintenance 54,143 23,543 - 77,686
Depreciation and amortization 112,745 62,043 (1 ) 174,787
Taxes:
Income taxes 65,849 20,871 (10,554 ) 76,166
Other than income 22,431 15,138 141 37,710

Operating Income $ 259,460 $ 94,242 $ 7,796 $ 361,498


Three months ended	NPC		SPPC		SPPC		SPPC		NVE			NVE
March 31, 2008	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	469,172	$	250,278	$	85,594	$	335,872	$	7		$	805,051

Energy Costs:
Fuel for power generation		164,021		57,587		-		57,587		-			221,608
Purchased power		93,750		90,106		-		90,106		-			183,856
Gas purchased for resale		-		-		66,896		66,896		-			66,896
Deferred energy costs - net		45,775		8,507		2,203		10,710		-			56,485
	$	303,546	$	156,200	$	69,099	$	225,299	$	-		$	528,845

Gross Margin	$	165,626	$	94,078	$	16,495	$	110,573	$	7		$	276,206

Other		57,095						33,505		1,075			91,675
Maintenance		16,650						6,472		-			23,122
Depreciation and amortization		40,630						21,440		-			62,070
Taxes:
Income taxes (benefit)		2,132						9,659		(3,172	)		8,619
Other than income		8,322						5,528		57			13,907

Operating Income	$	40,797					$	33,969	$	2,047		$	76,813

NOTE 3. REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions of Notes to Financial Statements in NPC’s and SPPC’s 2008 Form 10-K, for additional information regarding deferred energy accounting by the Utilities.

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

	March 31, 2009
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2009 DEAA	$	77,473	(1)	$	(19,813	)	$	(8,733	)	$	48,927
2009 Amortization		8			282			-			290
2009 Deferred Energy Costs (2)		(29,290	)		(14,922	)		4,220			(39,992	)
Nevada Deferred Energy Balance at March 31, 2009 - Subtotal	$	48,191		$	(34,453	)	$	(4,513	)	$	9,225
Cumulative CPUC balance		-			2,435			-			2,435
Western Energy Crisis Rate Case (effective 6/07, 3 years)		36,972			-			-			36,972
Reinstatement of deferred energy (effective 6/07, 10 years)		160,371			-			-			160,371

Total	$	245,534		$	(32,018	)	$	(4,513	)	$	209,003

Current Assets
Deferred energy costs – electric		91,286			-			-			91,286
Deferred Assets
Deferred energy costs - electric		154,248			-			-			154,248
Other Current Liabilities		-			(32,018	)		(4,513	)		(36,531	)
Total	$	245,534		$	(32,018	)	$	(4,513	)	$	209,003

(1)	Reflects ordered adjustments.
(2)	These costs to be requested in 2010 DEAA filings in February 2010.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Ely Energy Center

On February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. NVE and the Utilities still plan to proceed with the construction of the ON Line, which will link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state, allowing for the transfer of energy, including energy from renewable resources, between the Utilities. The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $72.6 million, including amounts related to the ON Line as of March 31, 2009. As such, management expects full recovery of the amounts expended through March 31, 2009.

Nevada Power Company

NPC ~~Ninth Amendment~~2009 Deferred Energy Rate Case

In February 2009, NPC filed an application to ~~its Integrated Resource Plan (IRP)~~create a new DEAA rate. In this application, NPC requests to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs. The new DEAA rate, if approved, will be effective October 1, 2009.

NPC General Rate Case

In ~~August~~December 2008, NPC filed its ~~ninth amendment~~statutorily required GRC. In this GRC, NPC is requesting the following:

·		Increase in general rates by $323.9 million, approximately a 14.95% increase;
·		ROE and ROR of 11.0% and 8.88%, respectively;
·		Authorization to recover the costs of major plant additions including the purchase of the Higgins Generating Station, construction of Clark Peaking Units, an upgrade to the emission control systems on existing units at the Clark Generating Station, installation of environmental equipment upgrades at the Reid Gardner Generating Station and new transmission and distribution projects;
·		CWIP in rate base for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen site;
·		Implementation of a low-income rate discount for customers;
·		Delay the rate effective date from July 1, 2009 to September 1, 2009. The delay in the rate effective date is contingent on PUCN approval to track and defer the revenues that NPC would otherwise collect during this sixty day period in a regulatory asset account and permit that NPC be allowed to record a carrying charge on these amounts. NPC would seek authority to amortize this regulatory asset in its next GRC filing, currently scheduled for December 2011.

In February 2009, NPC submitted its ~~IRP. In~~certification filing which lowered the amendment, NPC seeks approval to establish a regulatory asset for the 50% interest in the Carson Lake Project a minimum of 30 megawatts (MW) (nominally rated) of renewable energy (from a nominal net 24 MW to 40 MW) under the terms of a Joint Operating Agreement with an affiliate of Ormat Technologies Inc., and related operating and maintenance costs, depreciation and return on the plant until such time as it is includedincrease in general ~~rates.~~rates to $310.9 million, an approximate 13.64% increase, and lowered the requested ROR to 8.75%. Hearings are scheduled ~~for late November 2008.~~in mid-April through early May and, if approved, the new rates would be effective July 1, 2009; however, the collection period would not begin until September 1, 2009.

Sierra Pacific Power Company

SPPC Nevada Gas DEAA

In February 2009, SPPC filed an application to create a new DEAA rate. In this application, SPPC requests to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs. The new DEAA rate, if approved, will be effective October 1, 2009.

SPPC Nevada Electric DEAA

In February 2009, SPPC filed an application to create a new DEAA rate. In this application, SPPC requests to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2009.

SPPC California General Rate Case

In July 2008, SPPC filed a ~~general rate case.~~GRC and subsequently an amendment in December 2008 to the original filing. SPPC requested the following:

Increase in general rates of ~~$6.6~~$8.9 million, approximately an ~~8.1%~~11% increase;

~~Return on equity (ROE)~~

ROE and ~~rate of return (ROR)~~ROR of 11.4% and 8.81%, respectively;

Authorization to recover the costs of major plant additions, which include the ~~new~~ Tracy ~~541 MW (nominally rated) combined cycle generating plant,~~Generating Station, distribution plant additions and an increase to the California Energy Efficiency Program;

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

~~If approved, the new rates would be effective April 1, 2009.~~

~~Settled Regulatory Actions~~

~~Nevada Power Company~~

~~NPC Eighth Amendment to 2006 IRP~~

~~In May 2008, NPC filed its eighth amendment to its IRP. The PUCN issued its order in October 2008, which approved:~~

·	the purchase of the 598 MW (nominally rated) combined cycle Bighorn Power Plant from Reliant Energy LLC and Reliant Energy Asset Management LLC for approximately $510 million including costs for inventory and other closing costs and adjustments. The purchase was completed in October 2008.

construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen site with a scheduled commercial operation date of June 1, 2011. The estimated cost of this project is approximately $682 million (excluding allowance for funds used during construction). Additionally, the PUCN approved NPC’s request to include Harry Allen construction work in progress (“CWIP”) in rate base. On October 15, 2008, the Office of the Attorney General, Bureau of Consumer Protection (“BCP”), filed a petition for reconsideration and/or rehearing of that part of the PUCN’s Order on NPC’s eighth amendment to its 2006 IRP approving the construction of Harry Allen. NPC intends to oppose this petition but cannot predict how the PUCN will rule on the petition.

~~Table of Contents~~

Additionally, the PUCN, in its order, outlined certain minimum information regarding the Ely Energy Center (EEC) that shall be provided in NPC’s 2009 IRP filing including but not limited to an update of the engineering, construction and then current cost estimates for the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, an update of environmental costs and economic benefits attributed to the EEC and an update on the status of all required permits. Additionally, modification of the in-service dates will be addressed in the 2009 IRP filing. Finally, the PUCN directed NPC to continue to monitor load growth and congestion for the Sunrise Tap area and to address the issue of appropriate timing and expenditures for the Sunrise-500 kV Tap transmission line project in its 2009 IRP filing.

~~NPC 2008 Deferred Energy Rate Case~~

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

~~BTER Update~~

~~In August 2008, NPC filed an update to its going forward BTER which increased rates $62.7 million, resulting in a 3% increase. The updated going forward BTER became effective October 1, 2008.~~

~~NPC Seventh Amendment to its 2006 IRP~~

In March 2008, NPC filed its seventh amendment to its 2006 IRP. Included in the amendment are several initiatives, all of which comport with the goal of providing clean, safe, and reliable electricity to NPC’s customers at reasonable and predictable prices. However, as a result of the potential acquisition of the Bighorn Power Plant, announced in April 2008, NPC resubmitted its seventh amendment to its IRP and filed an eighth amendment in May 2008. Significant requests that remained in the resubmitted seventh amendment include:

·	~~Approval to acquire a 50% interest in the Carson Lake Project.~~

·	~~Approval to construct the 6 MW (nominally rated) Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Gas Pipeline.~~

·	~~Approval of an updated load forecast.~~

~~On July 30, 2008, the PUCN approved the seventh amendment filing.~~

~~NPC Fifth Amendment to its 2006 IRP~~

In December 2007, NPC filed its fifth amendment to its 2006 IRP requesting approval of three items: 1) a revised Demand Side Management Plan; 2) a settlement agreement and new long-term power purchase agreement for approximately 50 MW of summer season capacity; and 3) a new long-term tolling agreement that will provide 570 MW of unit contingent summer season capacity. In March 2008, a stipulation between NPC and the intervening parties was accepted by the PUCN which recommended approval of the three items, as requested.

~~Sierra Pacific Power Company~~

~~SPPC Third Amendment to its 2007 IRP~~

In May 2008, SPPC filed a third amendment to its IRP along with NPC’s eighth amendment. As discussed above for NPC, the PUCN, in its order received October 2008, outlined certain minimum information regarding the EEC that shall be provided in SPPC’s amendment to its 2007 IRP, including but not limited to, an update of the engineering, construction and then current cost estimates for the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, an update of environmental costs and economic benefits attributed to the EEC and an update on the status of the all required permits. Additionally, modification of the in-service dates will be addressed in SPPC amendment to its 2007 IRP filing.

~~Table of Contents~~

~~SPPC Nevada Gas DEAA~~Hearings are scheduled for June 2009 and, ~~BTER Update~~

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

~~SPPC Nevada Electric DEAA and BTER Update~~

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

~~SPPC Nevada Gas BTER Update~~

In August 2008, SPPC filed an update to its going forward BTER which increased rates an additional $3 million, resulting in an additional 2% increase. The updated going forward BTER became effective October 1, 2008.

~~SPPC Nevada Electric BTER Update~~

In August 2008, SPPC filed an update to its going forward BTER which increased rates $18 million resulting in a 2% additional increase. The updated going forward BTER became effective October 1, 2008.

~~SPPC Second Amendment to its IRP~~

In March 2008, SPPC filed its second amendment to its 2007 IRP requesting approval to modify the schedule and development budget for the EEC in a manner consistent with the amendment to the NPC IRP described above, approval of a purchase power agreement, authority to fund CO2 research and approval of a revised load forecast. However, similar to NPC’s resubmission of its seventh amendment as discussed above, SPPC also resubmitted a second amendment to its 2007 IRP and filed a third amendment in May 2008. The requests that remained in the resubmitted second amendment were the approval of a purchase power agreement, authority to fund CO2 research and approval of a revised load forecast. The update of the EEC that was originally in the second amendment was included in the third amendment. On July 30, 2008, the PUCNif approved, the ~~second amendment filing.~~

~~SPPC Nevada 2007 General Rate Case (GRC)~~

Innew rates would be effective at the earliest on December 2007, SPPC filed its statutorily required electric GRC. The filing requested a return on equity (ROE) and rate of return (ROR) of 11.5% and 8.73%, respectively, and an increase to general revenues of $110.8 million.

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

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

·	~~Return on equity (ROE) and rate of return (ROR) of 10.6% and 8.41%, respectively;~~

·	~~Authorization to recover the costs of the new Tracy 541 MW (nominally rated) combined cycle generating plant; and~~

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

~~SPPC Nevada 2003 GRC~~

In its 2003 GRC, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project. SPPC's participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable.

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

~~Table of Contents~~

On March 18, 2008, the PUCN issued an order to place $5.8 million (Nevada jurisdiction) of the previously disallowed $43 million unreimbursed costs in a regulatory asset account without a carrying charge. As a result of this order and in accordance with SFAS 90, Accounting for Abandonments and Disallowances of Plant Costs, SPPC recognized approximately $4.3 million in income for the nine months ended September 30, 2008. The remaining difference of $1.5 million will be recognized over an approximate six year period. The time for any party to appeal the PUCN’s decision ended in June 2008 and no appeals were filed.

~~SPPC California Energy Cost Adjustment Clause~~

In April 2008, SPPC filed to decrease rates by $12.2 million, a decrease of 15.2%. The California Public Utilities Commission approved the filing in August 2008. The rates requested in this filing were effective September 1, 2008.2009.

NOTE 4. LONG-TERM DEBT

As of ~~September 30, 2008,~~March 31, 2009, NPC’s, SPPC’s and ~~SPR’s~~NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

NPC SPPC SPR Holding Co. and Other Subs. SPR Consolidated
2008 $ (119 ) $ 539 $ - $ 420
2009 7,218 600 - 7,818
2010 8,004 - - 8,004
2011 369,924 - - 369,924
2012 136,448 100,000 63,670 300,118
521,475 101,139 63,670 686,284
Thereafter 2,475,506 1,183,250 460,539 4,119,295
2,996,981 1,284,389 524,209 4,805,579
Unamortized Premium(Discount) Amount (13,124 ) 9,617 800 (2,707 )
Total $ 2,983,857 $ 1,294,006 $ 525,009 $ 4,802,872

	NPC			SPPC		NVE Holding Co. and Other Subs.		NVE Consolidated
2009	$	3,536		$	-	$	-	$	3,536
2010		8,004			199,930		-		207,934
2011		369,924			-		-		369,924
2012		136,449			100,000		63,670		300,119
2013		7,146			250,000		-		257,146
		525,059			549,930		63,670		1,138,659
Thereafter		3,093,360			843,500		421,539		4,358,399
		3,618,419			1,393,430		485,209		5,497,058
Unamortized Premium(Discount) Amount		(12,694	)		9,534		630		(2,530	)
Total	$	3,605,725		$	1,402,964	$	485,839	$	5,494,528

The preceding table includes obligations related to capital lease obligations. The approximate $119 thousand credit for NPC in 2008 includes semi-annual capital lease payments, which were due and paid prior to September 30, 2008.

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

~~Financing Transactions~~

~~Sierra Pacific Resources~~

~~Debt Repurchase~~

In October 2008, SPR repurchased approximately $19 million of its 6.75% Senior Notes due 2017 from SPR’s cash on hand. As of October 31, 2008, the remaining balance on the 6.75% Senior Notes is $191.5 million.

Nevada Power Company

Revolving Credit Facilities

~~In October 2008,~~On March 2, 2009, NPC ~~borrowed approximately $466.4 million from~~amended its $600 million Second Amended and Restated Revolving Credit ~~Facility~~Agreement, which ~~was used along with cash on hand~~matures in November 2010, to ~~fund~~remove a bankrupt lending bank from the ~~approximately $510 million acquisition~~facility. This amendment reduced the capacity of the ~~Bighorn Generating Station.~~facility to approximately $589 million.

On January 5, 2009, NPC entered into a new $90 million supplemental revolving credit facility. The ~~Bighorn Generating Station~~facility has a term of 364 days, and is ~~a 598 MW (nominally rated), natural gas fired combined cycle~~secured by General and Refunding Mortgage bonds. This credit facility matures in January 2010, and is in addition to NPC’s existing approximate $589 million revolving credit facility.

General and Refunding Mortgage Notes, Series SV

~~In July 2008,~~On March 2, 2009, NPC issued and sold $500 million of its ~~6.5%~~7.125% General and Refunding Mortgage Notes, Series S,V due ~~2018~~2019. The net proceeds of the issuance were used to repay ~~$270~~approximately $404 million of amounts outstanding under NPC’s approximate $589 million revolving credit facility, and for general corporate purposes.

~~Redemption Notice~~

~~On July 15, 2008, NPC provided a notice of redemption to the holders of all of its remaining 9.00%~~ General and Refunding Mortgage Notes, Series G, for approximately $17.2 million. The notes were redeemed on August 15, 2008, at 104.50% of the stated principal amount, plus accrued interest to the date of redemption. NPC used available cash on hand to redeem these notes.

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

~~In July 2008,~~On January 12, 2009, NPC ~~converted the $13~~issued and sold $125 million ~~principal amount Coconino County, Arizona Pollution Control~~of its 7.375% General and Refunding ~~Revenue Bonds~~Mortgage Notes, Series ~~2006B bonds,~~U due 2039 and the $15 million principal amount Clark County Nevada Pollution Control Revenue Bonds, Series 2000B due 2009, (collectively, the “Bonds”) from auction rate securities to variable rate demand notes.2014. The ~~purpose of these conversions was to reduce interest costs and volatility associated with these Bonds. NPC purchased 100%~~net proceeds of the ~~Bonds on that date with proceeds from its~~issuance were used to repay approximately $124 million of amounts outstanding under NPC’s revolving credit facility and available cash, and are the sole holder of the Bonds until such time as NPC determines to reoffer the Pollution Control Bonds to investors. The Bonds remain outstanding and have not been retired or cancelled. However, because NPC is the sole holder of the Bonds, for financial reporting purposes the investment in the Bonds and the indebtedness will be offset for presentation purposes.facility.

~~Table of Contents~~

Sierra Pacific Power Company

Revolving Credit Facility

On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $332 million.

Conversions

Conversion of ~~Humboldt~~Washoe County ~~Pollution Control~~Water Facilities Refunding Revenue Bonds

On January 14, 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series ~~2006~~

~~In October 2008, SPPC converted the $49.8 million principal amount, Humboldt County, Nevada Pollution Control Refunding Revenue Bonds Series 2006~~2007A bonds, due ~~2029~~2036 (the ~~“Pollution Control~~“Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the ~~Pollution Control~~Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Pollution Control Bonds until such time as SPPC determines to reoffer the Pollution Control Bonds to investors. The Pollution Control Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Pollution Control Bonds, for financial reporting purposes the investment in the Pollution Control Bonds and the indebtedness will be offset for presentation purposes.

~~General and Refunding Mortgage Notes, Series Q~~

On September 2, 2008, SPPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013. The net proceeds of the issuance were used to repay $238 million of amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

~~Maturity of General and Refunding Mortgage Bonds, Series A~~

On June 2, 2008, the 8.00% General and Refunding Mortgage Bonds, Series A, in the aggregate principal amount of approximately $99.2 million, matured. SPPC paid for the maturing debt plus interest with the use of $90 million from its revolving credit facility, which was repaid with the proceeds of the Series Q offering, plus cash on hand.

~~Conversion of Washoe County Water Facilities Refunding Revenue Bonds~~

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

NOTE 5. DERIVATIVES AND HEDGING ACTIVITIES

~~SPR,~~NVE, SPPC and NPC apply SFAS ~~No.~~ 133, ~~"Accounting for Derivative Instruments and Hedging Activities" (“SFAS 133”),~~ as amended by SFAS 138, SFAS ~~No.~~ 149, SFAS ~~No.~~ 155, SFAS 157 and SFAS ~~No. 157.~~161. As amended, SFAS 133 establishes accounting and reporting standards for ~~derivative~~derivatives instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for ~~by the Utilities~~ under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value.

Adoption of SFAS 161

Effective January 1, 2009, NVE and the Utilities’ adopted SFAS 161, which is intended to enhance the current disclosure framework in SFAS 133. The Statement requires the objectives for using derivative instruments be disclosed in terms of underlying risk and accounting. This Statement requires NVE and the Utilities to distinguish between instruments used for risk management and instruments used for other purposes. SFAS 161 requires disclosing the fair values of derivative instruments and their gains and losses for the period, providing more information about credit-risk related contingent features and describing the volume of their derivative activity.

~~Table of Contents~~

Commodity Risk

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

~~Adoption of SFAS 157~~Credit Risk Contingent Features

~~Effective January 1, 2008, SPR~~The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities ~~adopted SFAS 157, which defines fair value, establishes a framework for measuring fair value~~maintain their Moody’s, Fitch, and ~~enhances disclosures about assets and liabilities recorded~~S&P Senior Unsecured or equivalent ratings in place at ~~fair value.~~

~~SFAS 157 also establishes a three-level hierarchy which requires an entity~~the time the contracts were entered into. In the event that the Utilities’ Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to ~~maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Derivative instruments used by SPR and~~require the Utilities to ~~manage energy price risk~~post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of March 31, 2009, the maximum amount of collateral NPC and SPPC would be required to post under these agreements is approximately $216.5 million and $98.0 million, respectively, based on mark-to-market liability values, which are ~~valued using~~substantially based on quoted ~~exchange prices, external dealer prices~~market prices. Of this amount, approximately $117.7 million and ~~option pricing modules that utilize readily observable market parameters~~$54.6 million, respectively, would be required if NPC and SPPC are ~~therefore classified within~~downgraded one level 2and additional amounts of ~~the fair value hierarchy. The three levels~~approximately $98.9 million and $43.4 million would be required respectively if NPC and SPPC are ~~defined as follows:~~downgraded two levels.

Level 1 – Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

~~Level 3 – Unobservable inputs that are supported by little or no market activity and that are significant.~~

Determination of Fair Value

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps and options. Total risk management assets below do not include option premiums which are not considered a derivative asset. Option premiums upon settlement are recorded in fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism. Option premium amounts included in risk management assets at March 31, 2009 for NVE, NPC and SPPC were as follows (dollars in millions):

	Option Premiums
	March 31, 2009						December 31, 2008
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	13.5	$	10.2	$	3.3	$	13.3	$	9.7	$	3.6
Non-Current		5.0		4.1		0.9		5.6		4.2		1.4
Total	$	18.5	$	14.3	$	4.2	$	18.9	$	13.9	$	5.0

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

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

~~Table of Contents~~

Commodity Contracts	March 31, 2009 Fair Value Level 2 (as defined by SFAS 157) (dollars in millions)									December 31, 2008 Fair Value Level 2 (as defined by SFAS 157) (dollars in millions)
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current	$	-		$	-		$	-		$	2.8		$	2.0		$	.8
Risk management assets- noncurrent		1.7			1.2			.5			4.4			3.2			1.2
Total risk management assets		1.7			1.2			.5			7.2			5.2			2.0

Risk management liabilities- current		412.5			300.8			111.7			313.8			222.9			90.9
Risk management liabilities- noncurrent		30.9			23.2			7.7			53.4			35.2			18.2
Total risk management liabilities		443.4			324.0			119.4			367.2			258.1			109.1

Risk management regulatory assets/liabilities – net (1)	$	(441.7	)	$	(322.8	)	$	(118.9	)	$	(360.0	)	$	(252.9	)	$	(107.1	)

September 30, 2008
Fair Value
Level 2

December 31, 2007
Fair Value

SPR NPC SPPC SPR NPC SPPC

Risk management assets- current $ 17.3 $ 12.8 $ 4.5 $ 22.3 $ 16.1 $ 6.2
Risk management assets- noncurrent 8.9 6.5 2.4 12.5 9.1 3.4
Total risk management assets 26.2 19.3 6.9 34.8 25.2 9.6

Risk management liabilities- current 185.8 132.5 53.3 39.5 27.0 12.5
Risk management liabilities- noncurrent 35.2 22.6 12.6 7.4 5.1 2.3
Total risk management liabilities 221.0 155.1 65.9 46.9 32.1 14.8

Less prepaid electric and gas options 15.6 11.2 4.4 13.9 10.2 3.7

Risk management regulatory assets/liabilities – net(1)
$ (210.4 ) $ (147.0 ) $ (63.4 ) $ (26.0 ) $ (17.1 ) $ (8.9 )

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

(1)

When amount is negative it represents a Risk Management Regulatory Asset, when positive it represents a Risk Management Regulatory Liability. NVE and the Utilities would have incurred a loss for the period ending March 31, 2009 of $ (81.7) million, $(69.9) million, and $(11.8) million, respectively; however, in accordance with SFAS 71, NVE and the Utilities deferred these losses, which are included in the Risk management regulatory assets/liabilities amount above.

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The ~~Utilities~~Utilities’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the ~~Utilities~~Utilities’ open derivative positions with ~~its~~their counterparties and the changes in forward commodity prices. The ~~decrease~~increase in risk management ~~assets~~liabilities as of ~~September 30, 2008,~~March 31, 2009, as compared to December 31, ~~2007,~~2008, is mainly due to unfavorable open derivative positions on natural gas options held by the ~~Utilities~~Utilities’ to hedge energy price risk for their customers resulting from lower commodity prices for natural gas at ~~September 30, 2008~~March 31, 2009 relative to contract prices.

The following table shows the commodity volume of our commodity contracts:

	March 31, 2009 Commodity Volume (MMBTU) (Amounts in millions)						December 31, 2008 Commodity Volume (MMBTU) (Amounts in millions)
	NVE		NPC		SPPC		NVE		NPC		SPPC

Commodity volume assets- current		0.2		0.2		-		1.2		1.0		0 .2
Commodity volume assets- noncurrent		5.4		3.7		1.7		1.1		1.0		0 .1
Total commodity volume of assets		5.6		3.9		1.7		2.3		2.0		0.3

Commodity volume liabilities- current		122.6		89.7		32.9		119.9		86.7		33.2
Commodity volume liabilities- noncurrent		36.7		28.9		7.8		40.6		28.6		12.0
Total commodity volume of liabilities		159.3		118.6		40.7		160.5		115.3		45.2

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental Contingencies

Nevada Power Company

~~Reid Gardner Station~~NEICO

~~Surface and Groundwater Matters~~

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

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

In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an Order that requires all evaporation and fly ash settling ponds to be closed or lined with impermeable liners over the next ten years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Any future ponds will be double-lined with inter-liner leak detection in accordance with the most recent NDEP Authorization to Discharge Permit issued October 2005.

~~Pond construction and lining costs to satisfy the NDEP order expended through September 30, 2008 is approximately $45 million. No additional expenditures are projected through 2008.~~

In 2006 and 2007, the water division of NDEP has been in discussions with NPC regarding what additional surface and groundwater remediation may be required at the site, beyond the scope of the current pond relining project. The proposed solution was to enter into an Administrative Order on Consent (AOC) and the final form of the proposed AOC was delivered to NPC in December 2007. Until such time, NPC did not know the extent of the obligation or scope of work that would be required to effect site restoration due to the complexities associated with environmental remediation of the target media and the evolving standards of acceptable remediation standards. As a result, management was unable to reasonably estimate the cost of this comprehensive remediation project prior to concluding the negotiations and receiving the final AOC from the NDEP.

~~Table of Contents~~

In February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. The AOC has been designed to supersede previous Orders and takes a comprehensive approach to address historical environmental impacts associated with facility operations. Upon receiving the final document in December 2007, management was able to estimate a range of costs to satisfy the requirements of the AOC. As a result, NPC has recorded an asset retirement obligation of approximately $20 million, which it expects to receive regulatory recovery of, similar to the PUCN’s treatment of other asset retirement obligations. Other costs associated with the AOC are expected to include capital expenditures and remediation costs of approximately $32.3 million in addition to operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is initiated and additional characterization has been completed.

~~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 ~~or sale~~and sale.

Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As disclosed in Note 13, Commitments and Contingencies of the ~~property.~~Notes to Financial Statements, Environmental, in the 2008 Form 10-K, NPC was subject to various environmental proceedings which were settled as of December 31, 2008. NPC continues to comply with these environmental commitments. As of March 31, 2009, environmental expenditures did not change materially from those disclosed in the 2008 Form 10-K.

Litigation Contingencies

Nevada Power Company

Peabody Western Coal Company

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

Royalty Claim

On October 15, 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Co. (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and ~~SCE~~Southern California Edison in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

~~As discussed in more detail in~~The operating agent for the ~~2007 Form 10-K,~~Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint ~~owners were first served in the Missouri lawsuit in January 2005.~~Owners. NPC believes Peabody WC’s claims are without merit. In July 2008, the Court dismissed ~~the three~~all counts against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo ~~Tribal~~tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action ~~had been~~was stayed since October 5, ~~2004. In~~2004 until March, 2008 when the USU.S. District Court ~~lifted the stay and~~ referred pending discovery related motions to a Magistrate judge. ~~The Magistrate filed his Report~~Those discovery motions have now been resolved and ~~Recommendations on June 13, 2008 and the Navajo thereafter sought judicial review of the Magistrate’s Report and Recommendations by filing an Objection with the District Court on June 27, 2008.~~factual discovery is taking place. The parties ~~are awaiting the Judge’s decision.~~

~~Retiree Health Care and Reclamation Claims~~

~~In addition~~have committed to providing proposed recommendations for future proceedings to the ~~above action before the Missouri State~~ Court Peabody further asserted in 1994 that the Navajo Joint Owners are liable under the Coal Supply Agreement (CSA) for Retiree Health Care Costs (RHCC) and Final Reclamation Costs (FRC), which Peabody WC is obligated to pay after the CSA expires and the Kayenta Mine closes. In 1996, Salt River and the Navajo Joint Owners filed a complaint in the Maricopa County (Arizona) Supreme Court seeking determinations that they are not liable for RHCC or FRC or, alternatively, that Peabody WC cannot recover RHCC and FRC until after the CSA ends. The case was dormant for several years, while Peabody WC pursued other RHCC and FRC claims arising out of similar coal contracts. Settlement discussions, led by Salt River on both the RHCC matter and the FRC claim reached final approvals with Peabody WC and the Navajo Joint Owners in July 2008 (Settlement Agreement and Mutual Release with Peabody). As of September 30, 2008, NPC has a $16.7 million liability recorded which management has assessed as the approximate amount to be paid, and recorded a corresponding other regulatory asset for such claims, as management believes that these costs are recoverable through deferred energy. The underlying lawsuit and arbitration have both been dismissed.

~~Table of Contents~~

May 27, 2009.

~~Nevada Power Company and Sierra Pacific Power Company~~

~~Calpine Settlement~~

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

Claim Nos. 5177 and 5179 filed by SPPC and NPC relate to complaints filed with FERC in December 2001 under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in reaction to the Western United States energy crisis. The Settlement Agreement provided that, for Claim Nos. 5177 and 5179, SPPC and NPC would receive general unsecured claims in the Calpine bankruptcy proceeding of approximately $1.7 million and $1.3 million respectively, totaling $3 million. In February 2008, Calpine distributed shares of Calpine common stock to SPPC and NPC with respect to Claim Nos. 5177 and 5179, at the approximate value at the time of the distribution of approximately $1.3 million, and $1.1 million, respectively. The Utilities recognized these amounts as income for the nine months ended September 30, 2008.

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

The distributions discussed above represent approximately 80% of the balance owed to NPC and SPPC under the three proofs of claims filed. Management cannot predict if the remaining 20% will be recovered due to the status of Calpine’s bankruptcy proceedings, and as such has not recorded any further amounts as income. Subsequent to the distribution, NPC and SPPC sold all of their shares of Calpine common stock and recorded a gain of $1.8 million for the nine months ended September 30, 2008.

Sierra Pacific Power Company

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to ~~the Truckee Meadows Water Authority (TMWA)~~TMWA in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Under the terms of the contract with TMWA, SPPC is ~~required~~not entitled to ~~transfer~~receive the ~~hydro assets~~proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in ~~working condition,~~a manner reasonably acceptable to TMWA or ~~alternatively~~ SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the Farad flume and Farad Dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs for Farad Dam. The case went to trial before the Court in April 2008. On September 30, 2008, the Court ruled that SPPC was not time barred from reconstructing Farad Dam, and has coverage for the full rebuild costs, subject to coverage sub-limits set forth in the insurance policies. The Court further ruled that SPPC is entitled to recover $4 million for costs incurred to date on Farad Dam and that SPPC shall have three years to rebuild the dam from the date of the Court’s decision. In the event Farad Dam is not rebuilt, the ~~court~~Court determined SPPC would be entitled to actual cash value of approximately $1.3 ~~million; however,~~million. SPPC has requested the court to reconsider the cash value ~~determination in its decision.~~to reflect rebuild costs and the Insurers opposed. Parties are awaiting a decision from the Court. The Insurers ~~have 30 days from~~time to file an appeal on the Court’s decision ~~on reconsideration of~~has been suspended pending the Court’s ~~judgment to file an appeal.~~determination on the cash value reconsideration.

~~Table of Contents~~

Other Legal Matters

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

NOTE 7. EARNINGS PER SHARE ~~(EPS) (SPR)~~(NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans and the non-employee director stock plan. Due to the net loss for the three months ended March 31, 2009, these items are anti-dilutive and diluted EPS for the period is computed using the weighted average number of shares outstanding before dilution.

Emerging Issues Task Force, Participating Securities and the Two-Class Method under SFAS 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive.

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

	Three months ended September 30,				Nine months ended September 30,					Three months ended March 31,
	2008		2007		2008		2007			2009			2008
Basic EPS
Numerator ($000)

Net income applicable to common stock	$	150,783	$	152,222	$	210,975	$	193,583
Net income (loss)										$	(22,244	)	$	24,058

Denominator											��
Weighted average number of common shares outstanding		234,096,559		221,612,243		233,975,552		221,424,682			234,331,044			233,836,234

Per Share Amounts

Net income applicable to common stock	$	0.64	$	0.69	$	0.90	$	0.87
Net income (loss) per share – basic										$	(0.09	)	$	0.10

Diluted EPS
Numerator ($000)

Net income applicable to common stock	$	150,783	$	152,222	$	210,975	$	193,583
Net income (loss)										$	(22,244	)	$	24,058

Denominator(1)
Weighted average number of shares outstanding before dilution		234,096,559		221,612,243		233,975,552		221,424,682			234,331,044			233,836,234
Stock options		26,738		73,834		48,340		124,013			-			60,750
Non-Employee Director stock plan		66,130		48,513		59,810		44,597			-			56,313
Employee stock purchase plan		-		-		290		2,630
Restricted Shares		11,804		-		6,121		-			-			1,311
Performance Shares		453,901		234,212		409,156		187,502			-			367,364
		234,655,132		221,968,802		234,499,269		221,783,424			234,331,044			234,321,972

Per Share Amounts

Net income applicable to common stock	$	0.64	$	0.69	$	0.90	$	0.87
Net income (loss) per share – diluted										$	(0.09	)	$	0.10

(1) The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan due to conversion prices being higher than market prices for all periods. Under this plan, 1,072,678 and 909,795 shares for the periods ending March 31, 2009 and 2008, respectively, would be included if the conditions for conversions were met.									(1) The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan due to conversion prices being higher than market prices for all periods. Under this plan, 1,072,678 and 909,795 shares for the periods ending March 31, 2009 and 2008, respectively, would be included if the conditions for conversions were met.

~~(1)~~

The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the three and nine months ended September 30, 2008 and 2007, due to conversion prices being higher than market prices for all periods and are therefore anti-dilutive. Under the nonqualified stock option plan for the three and nine months ended September 30, 2008, 1,049,833 and 977,463 shares, respectively, would be included and 685,582 and 713,826 shares, respectively, would be included for the three and nine months ended September 30, 2007.

2423

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NOTE 8. ~~PENSION~~RETIREMENT PLAN AND ~~OTHER POSTRETIREMENT~~POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other postretirement costs for the three months ended ~~September 30~~March 31 follows. This summary is based on a December 31, 2008 measurement date for 2009 and a September 30, 2007 measurement date for 2008 (dollars in thousands):

Sierra Pacific Resources, consolidated

For The Three Months Ended September 30,
Pension Benefits Other Postretirement Benefits
2008 2007 2008 2007

Service cost $ 5,237 $ 5,725 $ 641 $ 268
Interest cost 10,677 9,855 2,683 2,570
Expected return on plan assets (11,463 ) (10,474 ) (2,088 ) (1,309 )
Amortization of prior service cost (265 ) 407 (257 ) 30
Amortization of net (gain)/loss 1,980 1,803 872 242
Amortization of Transition Obligation - - - 815

Net periodic benefit cost $ 6,166 $ 7,316 $ 1,851 $ 2,616

For The Nine Months Ended September 30,
Pension Benefits Other Postretirement Benefits
2008 2007 2008 2007

Service cost $ 16,506 $ 17,175 $ 1,922 $ 1,804
Interest cost 32,142 29,565 8,049 7,711
Expected return on plan assets (35,587 ) (31,422 ) (6,264 ) (3,927 )
Amortization of prior service cost 25 1,222 (771 ) 91
Amortization of net (gain)/loss 4,733 5,409 2,617 2,444
Amortization of Transition Obligation - - - 727

Net periodic benefit cost $ 17,819 $ 21,949 $ 5,553 $ 8,850

NVE, Consolidated
	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008

Service cost	$	4,709		$	6,022		$	577		$	565
Interest cost		11,036			10,790			2,637			2,218
Expected return on plan assets		(9,290	)		(12,661	)		(1,508	)		(2,032	)
Amortization of prior service cost		(448	)		408			(171	)		(748	)
Amortization of net (gain)/loss		6,894			772			1,273			890
Amortization of Transition Obligation		-			-			-			-
Settlement (gain)/loss		-			-			84			-

Net periodic benefit cost	$	12,901		$	5,331		$	2,892		$	893

Nevada Power Company

For The Three Months Ended September 30,
Pension Benefits Other Postretirement Benefits
2008 2007 2008 2007

Service cost $ 3,103 $ 3,273 $ 304 $ 260
Interest cost 5,334 4,744 631 543
Expected return on plan assets (5,496 ) (4,750 ) (675 ) (310 )
Amortization of prior service cost (205 ) 358 289 31
Amortization of net (gain)/loss 983 857 202 170
Amortization of Transition Obligation - - - 242

Net periodic benefit cost $ 3,719 $ 4,482 $ 751 $ 936

~~Table of Contents~~

	For The Nine Months Ended September 30,
NPC
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007			2009			2008			2009			2008

Service cost	$	9,715		$	9,819		$	912		$	779		$	2,393		$	3,550		$	310		$	295
Interest cost		15,944			14,233			1,893			1,628			5,270			5,353			607			555
Expected return on plan assets		(17,058	)		(14,250	)		(2,026	)		(929	)		(4,462	)		(6,067	)		(509	)		(680	)
Amortization of prior service cost		159			1,072			868			91			(433	)		363			289			179
Amortization of net (gain)/loss		2,339			2,572			606			511			3,298			375			287			218
Amortization of Transition Obligation		-			-			-			727			-			-			-			-
Settlement (gain)/loss														-			-			19			-

Net periodic benefit cost	$	11,099		$	13,446		$	2,253		$	2,807		$	6,066		$	3,574		$	1,003		$	567

Sierra Pacific Power Company

For The Three Months Ended September 30,
Pension Benefits Other Postretirement Benefits
2008 2007 2008 2007

Service cost $ 1,940 $ 2,138 $ 319 $ 380
Interest cost 5,045 4,775 2,013 1,548
Expected return on plan assets (5,668 ) (5,492 ) (1,378 ) (745 )
Amortization of prior service cost (62 ) 53 (550 ) -
Amortization of net (gain)/loss 913 867 658 492

Net periodic benefit cost $ 2,168 $ 2,341 $ 1,062 $ 1,675

SPPC
	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008

Service cost	$	2,061		$	2,178		$	251		$	253
Interest cost		5,471			5,086			2,014			1,626
Expected return on plan assets		(4,580	)		(6,265	)		(977	)		(1,317	)
Amortization of prior service cost		(26	)		52			(465	)		(931	)
Amortization of net (gain)/loss		3,425			336			978			657
Amortization of Transition Obligation		-			-			-			-
Settlement (gain)/loss		-			-			65			-

Net periodic benefit cost	$	6,351		$	1,387		$	1,866		$	288

For The Nine Months Ended September 30,
Pension Benefits Other Postretirement Benefits
2008 2007 2008 2007

Service cost $ 6,058 $ 6,415 $ 956 $ 1,368
Interest cost 15,194 14,324 6,041 5,569
Expected return on plan assets (17,601 ) (16,476 ) (4,134 ) (2,683 )
Amortization of prior service cost (74 ) 159 (1,651 ) -
Amortization of net (gain)/loss 2,168 2,600 1,975 1,770

Net periodic benefit cost $ 5,745 $ 7,022 $ 3,187 $ 6,024

SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” (SFAS 158) requires companies to eliminate the early measurement date and to measure their Defined Benefit Pension and Other Postretirement Plans consistent with their fiscal year end. SFAS 158 provided a transition alternative to the elimination of the early measurement date by allowing earlier measurements determined for year end reporting of the fiscal year immediately preceding the year that the measurement date provisions are applied to be used to calculate the additional expense. As such andIn 2008, in accordance with SFAS 158, ~~the amounts below represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007. SPR,~~NVE, NPC and SPPC recorded additional pension ~~and other postretirement benefits~~ costs, relating to the elimination of the early measurement date, to ~~beginning~~ retained earnings of $5.3 million, ~~and $1.0 million;~~ $3.6 million and ~~$0.6 million;~~$1.4 million, respectively, before taxes. Additionally, in 2008 in accordance with SFAS 158, NVE, NPC and ~~$1.4~~SPPC recorded additional post retirement benefit costs relating to the elimination of the early measurement date to retained earnings of $1.0 million, $0.6 million and $0.4 million, respectively, before taxes.

~~In November 2007,~~ These amounts represent the Board of Directors approved a change in the defined benefit pension plan for SPR’s management, professional, administrative, and technical employees, from a final average pay formula to a cash balance formula. Employees with combined age and service totaling 75 years or more, have the choice of staying with the current plan or electing to switchexpense attributable to the ~~new plan,~~three month period from September 30, 2007 to December 31, 2007. NVE has changed the measurement date for its benefit plans from September to December 31, which went into effect on April 1, 2008. Although these changes resulted in cost savings, the recent downturn in the equity and debt markets have caused a reduction in the asset values of the pension trust resulting in higher costs and liability values when the plan was re-measured in April 2008.coincides with NVE’s fiscal year end.

~~Table of Contents~~

AsIn the first quarter ended March 31, 2009, NVE made a result of the changes noted above, accrued retirement benefit obligations increased from December 31, 2007 for changes in the asset values of the pension trust and revisions to Other Post-Employment Benefits (“OPEB”) estimates, offset by a decrease in the obligation for changes in plan design associated with the cash balance formula. The net increase to accrued retirement obligations at September 30, 2008, was $57.8 million, $19.5 million and $34.8 million for SPR, NPC, and SPPC, respectively, with an offsetcontribution to the Regulatory Asset for Pension Plans. Additionally, included in the net periodic benefit costs above for Pension Benefits are $990 thousand, $231 thousand and $803 thousand for SPR, NPC and SPPC, respectively, and for Other Postretirement Benefits $1.9 million, $367 thousand and $1.6 million for SPR, NPC and SPPC, respectively, as a result of the changes noted above.

~~In the third quarter ended September~~ ~~30, the company made contributions to the~~ pension ~~plan and the other postretirement benefits~~ plan in the amount of ~~$22~~$20 million, with $13.5 million allocated to the 2008 plan year and ~~$8 million, respectively.~~the remainder to the 2009 plan year. At the present time, it is anticipated that there ~~is not expected to~~will be ~~any~~ further contributions made to ~~either plan~~both the pension and other postretirement benefits plans in ~~2008.~~2009, however the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution.

NOTE 9. DIVIDENDS

On February ~~7, 2008, SPR’s Board of Directors~~5, 2009, NVE’s BOD declared a quarterly cash ~~dividen~~ddividend of ~~$0.08~~$0.10 per share which was paid onin March ~~12, 2008,~~2009 to common shareholders of record on ~~February 22, 2008.~~March 3, 2009. On April ~~28, 2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share, to common shareholders of record on May 23, 2008 which was paid on June 11, 2008. On August 4~~, ~~2008, SPR’s Board of Directors declared a quarterly cash dividend of $0.08 per share to common shareholders of record on August 22, 2008, which was paid on September 10, 2008.~~ ~~On October~~ 30, 2008, ~~SPR~~NVE’s Board of Directors declared a quarterly cash dividend of $0.10 per share to common shareholders of record on ~~December~~June 2, ~~2008~~2009, payable on June 17, 2009.

NOTE 10. SUBSEQUENT EVENTS

Sierra Pacific Power Company – California Asset Sale

In April 2009, SPPC entered into an agreement to sell its California electric distribution and generation assets to California Pacific Electric Company (the California Asset Sale). Based on the terms of the purchase agreement, SPPC will receive proceeds that include a premium on current net rate base assets as of the closing date, plus a working capital adjustment. Net rate base assets include utility plant in service, net and deferred credits and other liabilities. Such proceeds are expected to be ~~paid on December 17, 2008.~~above the current book value of the related net assets. The sale is expected to close in 2010, and is subject to obtaining necessary federal and state regulatory approvals. In accordance with SFAS No. 144, the related assets qualify as a sale of assets and will be reported separately as “Assets Held for Sale” in the balance sheet at June 30, 2009.

Below are the major classes of assets and liabilities related to the California Asset Sale (dollars in millions):

Assets	March 31, 2009		December 31, 2008

Utility Plant in Service	$	185.1	$	183.2

Less: Accumulated depreciation	$	66.7	$	65.0
Utility Plant in Service, net	$	118.5	$	118.2

Construction work-in-progress	$	6.3	$	5.5
Other current assets	$	7.1	$	6.8
Deferred Charges	$	3.5	$	3.0

Assets	$	135.4	$	133.5

Liabilities

Deferred Credits and Other Liabilities	$	14.9	$	15.1

Liabilities	$	14.9	$	15.1

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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),~~NVE, NPC or ~~Sierra Pacific Power Company (SPPC)~~SPPC; (NPC and SPPC are collectively referred to as the Utilities) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)

economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, weaker housing markets, ~~and~~ a decrease in tourism, particularly in ~~Southern~~southern Nevada, and cancelled or deferred hotel construction projects, which could affect customer collections, customer demand and usage patterns;

(2)	changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, including the effect of weaker housing markets and increased unemployment, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)

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

(4)

the ability and terms upon which ~~SPR,~~NVE, 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: continued volatility in the global credit markets, unfavorable rulings by the ~~Public Utilities Commission of Nevada (PUCN),~~PUCN, untimely regulatory approval for utility financings, and/or a downgrade of the current debt ratings of ~~SPR,~~NVE, NPC or SPPC;

~~(4)~~(5)

financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability and cost of capital either due to market conditions or as a result of the Utilities’ credit ratings, or interest rate ~~fluctuations resulting from, among other things, the credit quality of bond insurers that guarantee certain series of the Utilities’ auction rate tax-exempt securities;~~fluctuations;

~~(5)~~

changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

(6)

unseasonable weather, drought, threat of wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability to procure adequate supplies of fuel or purchased power and the cost of procuring such supplies, and could affect the amount of water available for electric generating plants in the Southwestern ~~United States;~~U.S., and could have other adverse effects on our business;

(7)

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), physical availability, sharp increases in the prices for fuel (including increases in ~~the price of coal and in the~~ long term transportation ~~costs for natural gas)~~costs) and/or power or a ratings downgrade;

(8)

further increases in the unfunded liability or changes in ~~environmental laws or regulations, including~~actuarial assumptions, the ~~imposition of limits~~interest rate environment and the actual return on ~~emissions of carbon dioxide from electric generating facilities,~~plan assets for our pension plan, which ~~could significantly~~can affect ~~our existing operations as well as our construction program, especially the proposed Ely Energy Center;~~future funding obligations, costs and pension plan liabilities;

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

(10)

construction risks, such as delays in permitting, changes in environmental laws, difficulty in securing adequate skilled labor, cost and availability of materials and equipment (including escalating costs for materials, labor and environmental compliance due to timing delays and other economic factors which may affect vendor access to capital), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

~~(10)~~

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

(11)

~~unfavorable~~changes in environmental laws or ~~untimely rulings in rate cases filed or to be filed by the Utilities with the PUCN,~~regulations, 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;imposition of limits on emissions of carbon dioxide from electric generating facilities, which could significantly affect our existing operations as well as our construction program;

~~Table of Contents~~

(12)

wholesale market conditions, including availability of power on the spot market and the availability to enter into gas financial hedges with creditworthy counterparties, 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;

(13)	whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act;

(14)

the discretion of NVE's Board of Directors regarding NVE's future common stock dividends based on the Board of Directors periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in NVE's and the Utilities' agreements;

(15)	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 national economy in general;

~~(14)~~(16)

changes in tax or accounting matters or other laws and regulations to which ~~SPR~~NVE or the Utilities are subject;

~~(15)~~(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;

~~(16)~~(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 gaming establishments in California, other states and internationally;

~~(17)~~(19)

employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work ~~stoppages;~~stoppages, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce; and

~~(18)~~(20)

unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

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

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

·	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;

·	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

·	may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

·	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

2927

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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)~~NVE and its two primary subsidiaries, ~~Nevada Power Company (NPC)~~NPC and ~~Sierra Pacific Power Company (SPPC),~~SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to ~~SPR (holding company)~~NVE and the Utilities collectively)., and includes the following:

~~In September 2008, SPR announced that NPC and SPPC will do business under the name NV Energy.~~

●	For each of NVE, NPC and SPPC:

	§	Results of Operations

	§	Analysis of Cash Flows

	§	Liquidity and Capital Resources

●	Regulatory Proceedings (Utilities)

SPR also announced that it will seek shareholders' approval to amend its corporate charter to change its corporate name from Sierra Pacific Resources to NV Energy, Inc. subject to shareholders' approval at a special meeting called for November 19, 2008. SPR would assume the new name at the time of such approval.

The name change for NPC and SPPC unifies under a single brand a company that serves Nevada’s energy needs from north to south. However, for purposes of financial reporting, rate filings, and contractual transactions, the corporate legal structures of SPR and the Utilities remains unchanged and will continue to be referred to as SPR, NPC, and SPPC.

~~Management’s Discussion and Analysis of Financial Condition and Results of Operations consists primarily of the following:~~

▪ ~~Results of Operations~~

▪ ~~Analysis of Cash Flows~~

▪ ~~Liquidity and Capital Resources~~

▪ ~~Energy Supply (Utilities)~~

▪ ~~Regulatory Proceedings (Utilities)~~

~~SPR’s~~NVE’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 generation, transmission, distribution 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~~NVE and account for substantially all of ~~SPR’s~~NVE’s assets and revenues. ~~SPR,~~NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers ~~(SPR,~~(NVE, NPC and SPPC), except for discussions that relate to all three entities or ~~to both~~the Utilities.

~~For~~NVE incurred a net loss of $22.2 million for the three months ended ~~September 30, 2008, SPR recognized~~March 31, 2009 compared to net income ~~applicable to common stock~~ of ~~$150.8 million compared to $152.2~~$24.1 million for the same period in ~~2007. For the nine months ended September 30, 2008, SPR recognized net income applicable to common stock of $211.0 million compared to $194.0 million~~2008. Consolidated gross margin increased for the ~~same period~~quarter by $7.7 million primarily due to increased rates as a result of SPPC's 2007 GRC, effective July 1, 2008; however, earnings decreased primarily due to increased other operating expenses, maintenance expense and depreciation, some of which are costs related to the purchase of the Higgins Generating Station and the construction of the Clark Peaking Units, which are not currently in ~~2007. See SPR’s,~~rates but are being requested in NPC’s current GRC, and ~~SPPC’s respective~~ ~~Results~~lower revenues as a result of ~~Operations~~milder weather. Other items which contributed to the decrease in earnings include higher interest charges and a decrease in AFUDC and other income. Interest charges increased due to the issuances of new debt to fund significant capital expenditures, which is not currently being recovered in NPC’s cost of capital. AFUDC decreased as a result of a decrease in construction activity and the completion of major capital projects in 2008. Other income decreased due to income earned in 2008 for ~~more details on~~ the ~~change in earnings.~~settlement with Calpine and reinstatement of previously disallowed costs related to Pinon Pine.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. 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, while its gas business typically peaks in the winter. The variations in energy usage by the Utilities’ customers due to varying weather and other energy usage patterns ~~necessitate~~necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

~~2008 and Beyond Outlook~~2009 Current Matters

~~In Southern~~

The economy in Nevada ~~population~~has been adversely affected by the recession facing the U.S. and the global economy, resulting in decelerated growth compared to prior years when Nevada was experiencing high growth. Tourism and gaming remain southern Nevada’s leading industries, driving construction activity, the housing market and employment in the region, and together comprising one of NPC’s largest classes of customers. Management continues ~~however~~to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas, which has decreased approximately 6.9% as of February 28, 2009 from a year ago. Additionally, the unemployment rate in Nevada is currently at 10.3% compared to 5.4% in 2008. The expected room growth rate for 2009 is 9.1%, concentrated primarily in Project City Center, which is developed and jointly owned by MGM Mirage, and 2.7% for 2010. Gaming properties in southern Nevada are experiencing financial difficulties, including meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases. Other economic conditions affecting Nevada include the national decrease in real estate market activity which makes it more difficult for individuals and businesses to sell their properties in order to relocate to Nevada.

As the Utilities’ service territories transition from a time of high growth to a much slower ~~pace than in prior years. As~~growth rate, management continues to place a ~~result~~significant emphasis on modifying our business strategies to reflect the foregoing economic indicators and their effect on various factors including, but not limited to:

·	customer growth;

·	load factors;

·	future capital projects and capital requirements;

·	managing operating and maintenance expenses within projected revenue growth;

·	our liquidity and ability to access capital markets;

·	collections on accounts receivable; and

·	counterparty risk.

Upon evaluation of ~~economic conditions both regionally and nationally, Southern Nevada~~the factors above, the Company has ~~experienced decreased activity in the real estate, construction and tourism markets. Additionally, the recent credit and~~reduced cash requirements for capital ~~markets crisis will likely impact Nevada’s economy as major commercial and residential developments are delayed or potentially halted due~~expenditures by approximately $120 million to ~~the inability~~$145 million for 2009 for total estimated cash requirements of $800 million to obtain or the high cost of credit and/or capital. However, in Clark County, an increase of 25,000 hotel rooms is expected by 2010, and NPC’s load forecast projects growth of approximately 1% and 4%$775 million for the ~~years 2009 and 2010, respectively.~~current year. The current recession, as well as recent volatility in the global credit and financial markets, has created an unprecedented level of uncertainty regarding future business conditions. As a result, our management is continually focusing on and reevaluating our assessments, strategies and projections for factors such as customer growth, load forecasts, capital expenditures, rising fuel costs, access to capital markets, collections on accounts receivable and counterparty risk among other factors. While management expects to maintain this process of continual reevaluation for the foreseeable future, it is not possible to predict how long ~~current market volatility~~the economic recession will continue or what its long-term effect will be on the economy in general or on our financial position, cash flows or results of operations in particular.

~~Despite current economic conditions, long-term energy needs continue to increase in~~2009 and Beyond

In 2009 and beyond, management will remain focused on implementing the ~~Western and Southwestern portions~~three part strategy of the ~~United States. At the same time, however, the development of generating facilities by utility companies has decreased. As a result, the cost of~~ energy and natural gas continues to change with increased demand and the decline in the ability to meet those demands. The economics of this situation coupled with variations in weather, the capabilities and limits on the Utilities, owned generating facilities, transmission constraints, regulations, and changes and potential changes in environmental laws are significant business issues for the Utilities. As a result, the Utilities’ strategies, as evidenced by their most recent amendments to their Integrated Resource Plans (IRP), are aimed at reducing dependence on purchased power by the use ofsupply plan which includes energy efficiency and conservation programs, purchase and ~~diversifying fuel mix, including~~development of renewable energy projects and ~~owning more~~expansion of traditional generating ~~facilities.~~

~~Table of Contents~~

~~2008 Key Objectives~~

·	~~Management of Energy Resources~~

o	~~Energy Efficiency and Conservation Programs~~

o	~~Purchase and Development of Renewable Energy Projects~~

o	~~Construction of Generating Facilities~~

o	~~Management of Energy Risk, including fuel and purchased power costs~~

·	~~Management of Environmental Matters~~

·	~~Management of Regulatory Filings~~

·	~~Further Broaden Access to Capital~~

~~Management of Energy Resources~~

~~Energy Management encompasses~~capacity and transmission capability to move energy ~~efficiency and conservation programs, diversification of fuel mix, optimization of generation assets,~~throughout the state. Additional key objectives include management of energy risk, ~~which includes the purchase~~management of ~~short term~~environmental matters, management of regulatory filings and ~~long term supply contracts, transmission, storage, reliability and efficiency, and regulatory and legal considerations. The ability~~ to ~~balance and optimize these functions is a significant business challenge that we face.~~further broaden access to capital.

Energy Efficiency and Conservation Programs

A part of our strategy to reduce dependence on purchased power is to manage our resources against our load requirements with energy efficiency and conservation programs. As such, the Utilities’ have committed to spending approximately $135 million from 2008-2010 towards increasing efficiency and qualified conservation programs. NPC and SPPC have received PUCN approval of approximately $110.5 million and $29.8 million, respectively for the years 2008-2010, which will be deferredprograms, also known as ~~a regulatory asset subject to prudency review by the PUCN. The PUCN approval of the demand-side management (“DSM”) budget increase was a key step in expanding the energy savings yield from the~~ DSM programs.

NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public and low income). ~~After~~

The Utilities are planning to invest between $45 million and $60 million in DSM programs in 2009. The final amount will be determined by numerous factors, such as the ~~DSM percentage allowance, as described below, is fully utilized, NPC’s~~economy, the impact of federal government stimulus legislation, performance of existing and ~~SPPC’s strategy is to continue to implement cost-effective DSM programs.~~

~~Furthermore, the Portfolio Standard, discussed below, allows energy efficiency measures from qualified conservation~~new programs to meet up to 25% of the Portfolio Standard. A portfolio energy credit is created for each kWh of energy conserved by qualified energy efficiency programs. Energy saved during peak demand hours earns double the portfolio energy credits. In October 2008, the PUCN accepted the Utilities Portfolio Standard Annual Report for Compliance Year 2007 (the “Portfolio Report”). In the Portfolio Report, the Utilities reported that through energy efficiency measures they achieved 60% of the allowable 25% that may be used to meet the Portfolio Standard. In addition, NPC reported that it is in a position to achieve the maximum 25% in 2008.and many other factors.

Purchase and Development of Renewable Energy Projects

The Utilities have embarked on a strategy to invest in renewable energy that, along with purchased power contracts and an increase in DSM programs, will enhance the opportunity for the Utilities to fully meet the ~~renewable energy portfolio standard (Portfolio Standard)~~Portfolio Standard as required by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewables.

In 2009 and 2010, the Utilities are required to obtain an amount of PECs equivalent to 12% of their total retail energy from renewables. In April 2009, the Utilities filed their annual compliance report which reported compliance with the standard; however, the PUCN has not yet ruled on the filing. The Utilities continue to develop and explore sources for renewable ~~energy resources.~~energy. NPC’s current capital budget includes investing approximately ~~$355~~$110 million for renewable energy projects through ~~2012.~~

Nevada law sets forth the Portfolio Standard, requiring providers of electric service to acquire, generate, or save a specific percentage of its total retail energy sales from renewable energy resources (Renewables). Renewables include biomass, geothermal, solar, waterpower and wind projects. In 2008, the Utilities are required to obtain 9% of their total energy from Renewables. The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015. Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources.

~~Table of Contents~~

Nevada law requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In the Utilities’ Portfolio Report NPC reported that with PUCN approval of a sale and purchase of SPPC’s excess non-solar portfolio credits (PCs), NPC met the non-solar Portfolio Standard. SPPC reported compliance with the non-solar component of the Portfolio Standard. However, due to the late commercial operation of planned solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard. Additionally, the report described the Utilities ongoing activities to reach full compliance with the Portfolio Standard in the near future.

The PUCN issued its Order accepting the Utilities’ Portfolio Standard Annual Report for Compliance Year 2007 and accepted a stipulation that granted an exemption from meeting the Portfolio Standard. In addition, because the Utilities took reasonable efforts to comply with the Portfolio Standard the PUCN waived any administrative fines or penalties for non-compliance.

In May 2008, NPC re-filed its 7th amendment to its 2007-2026 Integrated Resource Plan with the PUCN (“2006 Resource Plan”). Included in the amendment are renewable energy requests which seek approvals to acquire a 50% interest in a minimum 30 MW geothermal project (“Carson Lake Project”) and to construct a 6 MW Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Pipeline. In July 2008, the PUCN approved the 7th amendment. Both projects are scheduled for commercial operation in late 2010. In August 2008, NPC filed its ninth amendment to its IRP. In the amendment NPC seeks approval to establish a regulatory asset for the Carson Lake Project and related operating and maintenance costs, depreciation and return on the plant, until such time it is included in general rates.2011.

~~Construction~~Expansion of Traditional Generating ~~Facilities~~

~~Ely Energy Center~~and Transmission Capacity

~~As discussed in more detail in the 2007 Form 10-K, included in the Utilities’ IRP and various amendments is~~In 2009, NPC continues the construction of the ~~Ely Energy Center that consists of two 750~~500 MW coal generation units to be located near Ely, Nevada and a 250-mile 500 kilovolt (kV) transmission line that would deliver electricity from the Ely Energy Center and from any possible future renewable resource projects in the area, as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state. In May 2008, the Utilities filed amendments to their IRP’s. Among other items, the Utilities requested permission to file the required IRP amendment regarding final approval of the Ely Energy Center in April 2010, after the issuance of required permits and bids for equipment and engineering, procurement and construction costs are obtained. This request would give the Utilities a better opportunity to evaluate the feasibility of the Ely Energy Center for factors such as, but not limited to, the effects of construction costs, carbon dioxide and climate change legislation, commodity prices and electricity demand in Nevada. However, in October 2008, the PUCN ruled certain information regarding the Ely Energy Center and other alternatives shall be provided in NPC’s 2009 IRP filing and SPPC’s corresponding amendment to its 2007 IRP.

~~Natural Gas Generating Units~~

In 2006, SPPC began construction of a 541 MW gas fired high efficiency combined cycle generator at the Tracy Plant, which was completed in July 2008. In 2007, NPC began the construction of 619 MWs of natural gas-fired combustion turbine peaking units at Clark Station. The first block of approximately 206 MWs became commercially operable in July 2008 and the remaining two blocks are expected to be completed by the end of the fourth quarter of 2008. Additionally, in 2007, NPC began construction of a 500 MW(nominally rated) natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011.

Currently, the expansion at the Harry Allen Generating Station is the only generating project under construction. The Utilities do not anticipate any new construction or purchases of generating facilities in the near future. In ~~October 2008,~~July 2009, NPC purchased a 598 MW (nominally rated), natural gas fired combined cycle power plant, the Bighorn Power Plant (“Bighorn”), from Reliant Resources, Inc., for approximately $510 million, including costs for inventory and other closing costs and adjustments. In NPC’s 8th amendment towill file its triennial 2009 IRP with the PUCN, ~~approved the purchase of Bighorn and NPC~~which will include ~~the acquisition costs in its General Rate Case to be filed in December 2008. Also approved by the PUCN in NPC’s 8th amendment to its IRP is~~ the construction of the Harry Allen Station discussed above, and the approval to include the construction costs in rate base which allows NPC to earn a return on its investment prior to the time the plant becomes operational.ON Line.

Management of Energy Risk

~~For the remainder of 2008 and for the future, the~~The Utilities have open positions resulting from the management of their portfolio of generation resources, load obligations, and purchased power and fuel contracts, due to unfolding developments in regional energy markets. The risks associated with the open positions are addressed in various ways. The Utilities implementimplemented a prudent strategy of piecemeal procurements transacted in regular intervals and completed before the start of the peak summer season. This provides the Utilities with ample opportunities for optimizing their portfolio on a rolling basis in anticipation of changes in system conditions, load forecasts, and regional energy market fundamentals. The Utilities also coordinate the planned maintenance schedules of their owned generating plants and transmission facilities with expectations of start dates of new generating plants or purchased power contracts. In addition, in 2008 the Utilities received PUCN approval to implement a longer term sales program for non-peaking months. The longer term sales program will allow the Utilities to sell their excess energy during non peak months on the open market.

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Management of Environmental Matters

~~The impact environmental~~Environmental laws ~~can have on~~affect existing generating facilities and current and prospective capital construction ~~projects~~projects. Such effects include but are not limited to increased costs, closure of existing facilities, mandated equipment upgrades, and termination of the construction of facilities. Environmental laws already affect the energy we ~~buy~~buy; as discussed above under Purchase and Development of Renewable Energy ~~Projects~~. For the remainder of 2008 and the next four years, NPC is projected to spend approximately $126.0 million on certain major environmental projects/upgrades. Additionally, as discussed above, under ~~Construction of Generating Facilities, Ely Energy Center, environmental laws will play a significant role in the construction of Ely Energy Center.~~Projects.

A key objective for the Utilities in ~~2008~~2009 will be to enhance and maintain our energy infrastructure investments in ways that meet customer demand for reliable energy in an efficient and environmentally responsible manner. The Utilities believe that a diverse and balanced portfolio of energy resources represents opportunity for reliability and cost control, yet are also mindful of our overriding environmental responsibility. The Utilities are committed to making technology choices with a primary focus on limiting emissions and optimizing our investments so that prices remain competitive. To meet the growing demand for power, the Utilities are investing in a new generation of highly efficient and environmentally advanced power plants, both coal and natural gas fired as well as adding new environmental controls to their existing plants. To help manage load demand, the Utilities are also increasing their participation and development of new energy efficiency and demand side conservation programs.

Management of Regulatory Filings

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for quarterly rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every three 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. Furthermore, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement. Resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases. The Utilities incur costs for such items as deferred fuel and purchased power costs, operations and maintenance and capital projects; however, as costs are not recovered through rates until approved by ~~regulators. The~~regulators, the timing between costs incurred and recovery is considered regulatory lag. In some cases, the loss due to regulatory lag is not recovered. As such, timely and accurate filings of these various rate cases is essential to the Utilities’ operating and financial performance as it reduces regulatory lag, which has a direct effect on the cash flows, and in some cases earnings, of the Utilities. Furthermore, the timing of the ~~filings/~~filings and subsequent decisions can affect the timing of construction and thus the economic benefits. As a result, the Utilities file quarterly BTER updates to minimize exposure to changes in fuel and purchased power expense and file amendments to IRP’s as changes in resource needs occur, and under their general rate case, pursuant to recent Nevada law, may elect to include in their filing future projected costs particularly in the case of major construction projects and related operating and maintenance expense, where significant amounts of capital are required to reduce regulatory lag.occur.

Significant ~~decisions or~~ filings pending regulatory outcome in ~~2008~~2009 include ~~but are not limited to,~~NPC’s GRC and SPPC’s ~~2007 GRC, amendments to the Utilities’ IRPs, and~~California GRC. For a more detailed discussion of the filing ~~of NPC’s GRC in late 2008. See~~requests, see Note 3, Regulatory Actions of the ~~Condensed~~ Notes to Financial ~~Statements in this Form 10-Q.~~Statements.

Further Broaden Access to Capital

~~In 2008, the Utilities have generated~~A significant focus in 2009 will again be to generate sufficient cash from operations to meet ~~their~~ operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs. ~~Additionally,~~

Commodity prices and the ~~Utilities have utililized their revolving credit facilities and issued sufficient amounts~~amount of ~~debt to fund~~capital required for construction projects ~~and the acquisition of Bighorn. However significant amounts of capital may~~are projected to be ~~necessary~~significantly lower in 2009 compared to fund existing and prospective construction projects, as well as volatile energy costs. In response, in October 2008, NPC filed a financing application with the PUCN to increase and diversify our access to liquidity. Furthermore, the recent credit and capital markets crisis has significantly tightened the availability of credit to many companies and increased the cost of borrowing generally.2008. As a result, ~~SPR and the Utilities will continue to evaluate alternative access to capital.~~

As a result of economic conditions discussed earlier, the acquisition of Bighorn and the timing of certain projects, management reduced the Utilities’ 2008 through 2012 estimated cash construction requirement from that reported in the 2007 Form 10K. The Utilities have reduced 2008 cash construction requirements by approximately $200 million. Management currently estimates cash construction expenditures for the remainder of ~~2008 through 2012 to~~2009, the Utilities believe they will be approximately $5.5 billion. Some of the major capital projects include the Ely Energy Center for $2.2 billion, Harry Allen for $631 million, renewable development for $355 million and environmental upgrades for $126 million. Of these major projects approximately $1.0 billion has been approved by the PUCN. Management is likelyable to meet such financial obligations with a combination of internally generated funds and the use of the Utilities’ revolving credit ~~facilities, the issuance of long-term debt, and the issuance of equity by SPR. If~~facilities. However, 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 ~~rely more on their revolving credit facilities, and if necessary,~~ issue additional debt to support their operating costs or further delay capital ~~expenditures.~~expenditures, and NVE may need to issue additional equity securities. As such, maintaining sufficient liquidity through the use of the Utilities’ revolving credit facilities and maintaining our ability to issue new debt or equity securities on favorable terms continues to be a significant focus in 2009.

NV ENERGY, INC.

~~Table of Contents~~

~~SIERRA PACIFIC RESOURCES~~RESULTS OF OPERATIONS

~~RESULTS OF OPERATIONS~~NV Energy, Inc. (Holding Company) and Other Subsidiaries

~~Sierra Pacific Resources (Consolidated)~~NVE (Holding Company)

The ~~operating results of SPR primarily reflect those of NPC and SPPC, discussed later. The holding company’s~~Holding Company’s (stand alone) operating results included approximately ~~$31.3~~$9.4 million and ~~$31.9~~$10.4 million of long-term debt interest costs for the ~~nine~~three months ended ~~September 30,~~March 31, 2009 and 2008, ~~and 2007,~~ respectively.

~~During~~ The decrease in interest costs for the three months ended ~~September 30, 2008, SPR recognized net income applicable to common stock of approximately $150.8 million~~March 31, 2009 as compared to ~~$152.2 million for~~ the same period in ~~2007. The change~~2008 was primarily due to ~~an increase~~debt repurchase in ~~interest on long term debt and a decrease in AFUDC.~~

~~During the nine months ended September 30, 2008, SPR recognized net income applicable to common stock~~2008. See Note 6, Long-Term Debt of approximately $211.0 million compared to $193.6 million for the same period in 2007. The increase to net income applicable to common stock was primarily due to an increase in operating income as a result of NPC’s Base Tariff General Rates (BTGR), as a result of NPC’s 2006 GRC effective June 1, 2007 and SPPC’s 2007 GRC effective July 1, 2008 and an increase to AFUDC. These increases were partially offset by higher interest charges on long term debt and income recognized in 2007 for approximately $7.2 million (net of taxes) as a result of the settlement with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case, see Note 3, Regulatory Actions in the Notes to Financial Statements in the ~~2007~~2008 Form ~~10-K.~~10-K, for further discussion of the debt repurchase.

Other Subsidiaries

Other Subsidiaries of ~~September 30, 2008,~~NVE, except for NPC ~~had paid $54.9 million in dividends to SPR~~ and SPPC, ~~had paid $78.3 million in dividends~~did not contribute materially to ~~SPR. On October 30, 2008, SPPC declared an additional $160 million dividend to SPR.~~the consolidated results of operations of NVE.

NV Energy, Inc. (Consolidated)

See Executive Overview, Overview of Major Factors Affecting Results of Operations for NVE Consolidated.

ANALYSIS OF CASH FLOWS

Cash flows increased during the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 compared to the same period in ~~2007~~2008 primarily due to an increase in cash from financing activities and to a lesser extent a decrease in cash ~~used by~~from investing activities, partially offset by a decrease in cash from operating activities.

Cash From Operating ~~Activities~~Activities.. The decrease in cash from operating activities was primarily due to ~~increases~~lower revenues as a result of milder weather and to a lesser extent, changes in ~~energy~~customer usage patterns. Also contributing to the decrease in cash from operating activities was an increase in costs for operations and maintenance costs for generating facilities, the funding of approximately $20 million for pension plans, prepayments for land leases, a decrease in ~~excess of the~~accounts payable from December 31, 2008 for energy ~~revenue collected in rates, expenditures for conservation programs, site studies~~ and other suppliers, the timing of interest payments and, in 2008, NPC received a significant prepayment for transmission services. Partially offsetting these decreases was reduced spending for regulatory ~~activities in 2008. The decrease was partially offset by the settlement with Calpine, prepaid transmission revenues and a reduction in funding for retirement plans.~~activities.

Cash Used By Investing ~~Activities~~Activities. . Cash used ~~for~~by investing activities decreased ~~primarily~~slightly due to ~~the closing stages of major~~reduced construction ~~activity for the peaking units at Clark Station and the combined cycle natural gas power plant at the Tracy Generating Station which began in 2007 and 2006, respectively.~~activity.

Cash From Financing ~~Activities~~Activities. . Cash from financing activities increased primarily due to the issuance of ~~NPC’s $500~~approximately $625 million ~~of 6.5% General~~in new debt, partially offset by payments on the revolving credit facility and Refunding Mortgage Notes, Series S, due 2018, SPPC’s $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 offset partially by debt redemption and higher dividend paymentsincrease in dividends to ~~SPR shareholders in 2008.~~common shareholders.

LIQUIDITY AND CAPITAL RESOURCES ~~(SPR~~(NVE CONSOLIDATED)

Overall Liquidity

~~SPR’s~~NVE’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, in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of September 30, 2008 (in millions)
SPR NPC SPPC
Cash and Cash Equivalents $ 229.1 $ 177.7 $ 29.3
Balance available on Revolving Credit Facility 1,2
N/A 585.4 313.2
$ 229.1 $ 763.1 $ 342.5

1. ~~NPC’s and SPPC’s available balance reflects management's estimate of a reduction of approximately $11.0 million and $18.0 million, respectively, as a result of the~~

~~bankruptcy of a lending bank.~~

2. ~~As of November 4, 2008, NPC and SPPC had approximately $232.2 million and $266.1 million available under their revolving credit facilities.~~

~~Table of Contents~~

~~SPR~~

As of March 31, 2009, NVE, NPC and SPPC had cash on hand of approximately $2.6 million, $81.6 million, $28.9 million, respectively. NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as ~~United States~~U.S. treasury bills. In addition to cash on hand, NVE and ~~the Utilities’ revolving credit facilities,~~ the Utilities may issue debt up to ~~$665~~$281.5 million, on a consolidated basis, ~~subject to certain limitations discussed below and in~~which includes the use of approximately $268.0 million of the Utilities’ ~~respective sections,~~revolving credit facilities. See Factors Affecting Liquidity, Ability to ~~meet their respective financial obligations.~~

~~SPR~~Issue Debt, below. NVE and the Utilities anticipate with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that ~~they will be able to meet short-term operating costs, such as fuel and purchased power costs, with~~cash on hand, internally generated funds ~~including the recovery of deferred energy,~~ and the ~~use of their revolving credit facilities. To manage liquidity needs as a result of seasonal peaks in fuel requirements, SPR and the Utilities may use hedging activities. In order~~ability to ~~fund long-term capital requirements, SPR and the Utilities will likely meet such financial obligations with a combination of internally generated funds,~~issue debt, which includes the use of the Utilities’ revolving credit ~~facilities,~~facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and the ~~issuance~~Utilities do not recover the cost of ~~long-term~~fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity, NVE and the Utilities may be required to further delay capital expenditures, re-finance debt or issue equity.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and ~~capital contributions~~the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from ~~SPR from~~quarter to quarter and the ~~issuance of equity by SPR. In October 2008, NPC borrowed approximately $466.4 million from its~~Utilities may not be able to fully utilize the availability on their revolving credit ~~facility, along with cash on hand,~~facilities. NVE and the Utilities are projecting that their ability to ~~fund the approximately $510 million acquisition of the Bighorn Generating Facility from Reliant Resources. NPC's management regularly evaluates whether NPC needs to~~issue debt will increase ~~its revolving credit facility. However, as discussed earlier~~ in the ~~executive overview,~~second and third quarter of 2009, as the ~~Utilities have reduced their capital expenditures for the remainder of 2008~~Utilities’ operating income typically increases during this time period, and ~~for 2009~~new rates as a result of ~~current economic conditions.~~NPC’s GRC are expected to be in effect beginning July 1, 2009.

NVE and the Utilities do not have significant debt maturities in 2009 or 2010 other than their revolving credit facilities. As of April 30, 2009, NPC and SPPC had $18.3 million and $206.1 million, respectively outstanding on their revolving credit facilities including letters of credit. The Utilities’ long-term credit facilities expire in November 2010, and NPC’s Supplemental Revolving Credit Facility expires in January 2010.

There have been no changes to the credit ratings of NVE and the Utilities in the first quarter of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

~~SPR~~NVE (stand-alone) has approximately ~~$40.7~~$21.4 million ~~payable~~ of debt service obligations remaining for ~~2008, of~~2009, which ~~$38.3 million was paid in the nine months ended September 30, 2008. SPR~~it intends to pay ~~the remaining interest payments~~ through dividends from subsidiaries. (See ~~“Factors~~Factors Affecting Liquidity-Dividends from ~~Subsidiaries”~~Subsidiaries below).

During the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, there were no material changes to contractual obligations as set forth in ~~SPR’s 2007~~NVE’s 2008 Form ~~10-K for SPR.~~10-K. See NPC’s and SPPC’s respective sections for changes in their contractual obligations.

~~Financing Transactions~~

~~Debt Repurchase~~

Factors Affecting Liquidity

Effect of Holding Company Structure

As of ~~September 30, 2008, SPR~~March 31, 2009, NVE (on a stand-alone basis) ~~has~~had outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; ~~$210.5~~$191.5 million of its unsecured 6.75% Senior Notes due 2017; and ~~$250~~$230 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, ~~SPR’s~~NVE’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~~NVE’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 ~~September 30, 2008, SPR,~~March 31, 2009, NVE, NPC, SPPC and their subsidiaries had approximately ~~$4.8~~$5.5 billion of debt and other obligations outstanding, consisting of approximately ~~$3.0~~$3.6 billion of debt at NPC, approximately ~~$1.3~~$1.4 billion of debt at SPPC and approximately ~~$524~~$485 million of debt at the holding company and other subsidiaries. Although ~~SPR~~NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, ~~SPR~~NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since ~~SPR~~NVE is a holding company, substantially all of its cash flow is provided by dividends paid to ~~SPR~~NVE by NPC and SPPC on their common stock, all of which is owned by ~~SPR.~~NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

In addition, certain ~~financing~~ 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. ~~However, as~~As a result of the ~~recent~~Utilities’ credit ~~rating upgrade of the Utilities’~~ratings on their senior secured debt toat investment grade by ~~Standard~~S&P and ~~Poor’s (S&P),~~Moody’s, these restrictions are suspended and ~~will~~are no longer be in effect so long as the debt remains investment grade by both ~~Moody’s and S&P. See Credit Ratings below.~~

rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to ~~SPR~~NVE could be jeopardized.

In the first quarter of 2009, NPC and SPPC paid dividends to NVE of $22 million and $108.8 million, respectively. On April 30, 2009, NPC and SPPC declared a $40 million and $20 million dividend, respectively, to NVE.

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Credit Ratings

~~SPR,~~NVE, NPC and SPPC are currently rated by ~~four~~three Nationally Recognized Statistical Rating ~~Organizations (NRSRO’s): Dominion Bond Rating Service (DBRS),~~Organizations: Fitch, ~~Ratings Ltd. (Fitch),~~ Moody’s ~~Investors Service, Inc. (Moody’s)~~ and S&P. DBRS is no longer covering NVE and the Utilities. The senior secured debt of NPC and SPPC is rated investment grade by ~~all four~~these three rating organizations. As of ~~October~~March 31, ~~2008~~2009, the ratings are as follows:

			Rating Agency
		~~DBRS~~	Fitch		Moody’s		S&P
~~SPR~~NVE	Sr. Unsecured Debt	~~BB (low)~~	BB-		Ba3		BB
NPC	Sr. Secured Debt	~~BBB (low)~~	BBB-*	~~BBB-~~	Baa3*	~~Baa3~~	~~BBB~~BBB*
NPC	Sr. Unsecured Debt		BB		Not rated	BB	~~Not rated~~	BB+
SPPC	Sr. Secured Debt	~~BBB (low)~~	BBB-*	~~BBB-~~	Baa3*	~~Baa3~~	~~BBB~~BBB*

*Investment grade

On May 15, 2008, S&P increased SPR’s corporate credit rating to BB from BB-, and unsecured notes at SPR were raised to BB from BB-. At the same time, the secured ratings at NPC and SPPC were raised to BBB from BB+, and unsecured notes at NPC were raised to BB+ from BB. As a result of these upgrades, all four rating agencies currently rate the Utilities’ senior secured debt investment grade.

S&P’s ~~Moody’s~~ and ~~DBRS’s~~Moody’s rating outlook for ~~SPR,~~NVE, NPC and SPPC is Stable. Fitch’s rating outlook for ~~SPR,~~NVE, NPC and SPPC is Positive.

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.

~~Credit Ratings of Bond Insurers~~

Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and downgrades of bond insurers, among other negative matters. The interest rates on certain issues of the Utilities’ auction rate securities of approximately $488 million as of September 30, 2008, are periodically reset through auction processes. These securities are supported by bond insurance policies provided by either Ambac Financial Group (AMBAC), Financial Guaranty Insurance Company (FGIC), or MBIA, Inc. (MBIA) (collectively, the “Insurers”), and the interest rates on those securities are directly affected by the rating of the bond insurer due to, among other things, the impact that such ratings have on the success or failure of the auction process. S&P’s and Moody’s ratings on these bonds are the ~~higher~~ of a bond issue's underlying rating and the Insurer's rating. As of September 30, 2008, AMBAC’s and MBIA’s credit ratings were investment grade or above. However, FGIC’s credit ratings were below investment grade. As a result, the bonds insured by FGIC are currently rated at the investment grade ratings of the Utilities’ secured debt. See ~~Credit Ratings~~ ~~above~~. The uncertainty with the Insurers' credit quality has had an impact on the Utilities’ interest costs for the first nine months of 2008. With the ongoing review of the credit ratings of the Insurers, the Utilities are experiencing higher interest costs for these securities.

In July and October 2008, NPC and SPPC converted portions of their auction rate securities to variable rate demand notes. This conversion will likely result in higher interest charges compared to prior year, but lower than the failed auction rates for this tax exempt debt. See ~~Financing Transactions~~ in NPC’s and SPPC’s Liquidity sections. If higher interest rates continue on the remaining auction rate securities outstanding, the Utilities may seek to convert the debt to other short-term variable rate structures, term-put structures and/or fixed-rate structures.

~~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 the Utility to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires the Utility to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of September 30, 2008 both Utilities were in compliance with these covenants.

Ability to Issue Debt

NV Energy, Inc.

Certain debt of ~~SPR~~NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of ~~consolidated~~ cash flow to fixed charges for ~~SPR’s~~NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1. ~~Under this covenant restriction, as of September 30, 2008, SPR would be allowed to incur up to $665 million of additional indebtedness on a consolidated basis.~~

~~Table of Contents~~

~~Notwithstanding this restriction,~~Additionally, under the terms of the debt, SPR would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the two Utilities’ integrated resource plans. NPC and SPPC ~~would also be~~are permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities. As of March 31, 2009, NPC had $15.3 million of letters of credit outstanding and SPPC had approximately $200 million borrowed and $17.1 million of letters of credit outstanding against its revolving credit facility; therefore, the remaining combined availability is $268 million. If however, the Utilities were to receive a credit rating downgrade and were required to post collateral, as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of availability under the revolving credit facilities would be further reduced.

Under these covenant restrictions, as of March 31, 2009, NVE (consolidated) would be allowed to incur up to $281.5 million of additional debt, which includes $268 million of combined usage under NPC’s and SPPC’s revolving credit facilities.

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

Nevada Power Company

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain ~~SPR~~NVE debt. ~~As of September 30, 2008, NPC had approximately $1.1 billion of PUCN financing authority.~~

On ~~October 20, 2008, NPC filed a financing application with~~February 4, 2009, the PUCN ~~requesting approximately~~approved NPC’s request for financing authority to issue up to $1.25 billion of ~~additional~~ long-term ~~financing authority.~~debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and authority to refinance up to approximately $471 million of long-term debt securities.

~~So long~~

NPC's $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2009, NPC was in compliance with these covenants. Based upon estimated interest expense, in order to maintain compliance with these covenants, NPC is limited to borrowing $314 million, which is less than the unused balance on its revolving credit facilities of $663.8 million.

All other financial covenants contained in NPC’s revolving credit facility agreement and its financing agreements are suspended, as NPC’s senior secured debt ~~containing financial covenants remains~~is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by ~~both~~either Moody’s ~~and~~or S&P, NPC would again be subject to the ~~restrictions contained in those debt agreements are suspended. However,~~limitations on indebtedness under these covenants.

Furthermore, NPC may be subject to NVE’s cap on additional consolidated indebtedness. See NVE’s Ability to Issue Debt. As of March 31, 2009, NPC’s own covenant restriction of $314 million is ~~limited by SPR’s~~less restrictive than NVE’s cap on additional consolidated indebtedness of ~~$665~~$281.5 million. ~~Notwithstanding this restriction under~~As such, NPC is limited by NVE’s cap on additional indebtedness of $281.5 million, which includes the terms of SPR’s debt, in addition to this amount, NPC would also be permitted to incur debt, including, but not limited to obligations incurred to finance property construction or improvements, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to its integrated resource plan. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

~~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 $665 million, depending on the Utilities~~ combined usage of ~~their~~the Utilities’ revolving credit facilities ~~at the time~~ of ~~the covenant calculations.~~$268.0 million.

Ability to Issue General and Refunding Mortgage Securities

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

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of ~~September 30, 2008, $3.3~~March 31, 2009, $4 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue ~~an additional $536~~$499.3 million of General and Refunding Mortgage Securities as of ~~September 30, 2008.~~March 31, 2009. That amount is determined on the basis of:

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

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

NPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its ~~General and Refunding Mortgage~~ Indenture, it will reduce the amount of securities issuable under ~~that indenture. See~~ the ~~2007 Form 10-K for additional information.~~Indenture.

Sierra Pacific Power Company

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain ~~SPR~~NVE debt.

As of ~~September 30, 2008,~~March 31, 2009, SPPC had approximately $495 million of PUCN financing ~~authority.~~authority, which expires on December 31, 2009.

SPPC's $332 million Amended and Restated Revolving Credit Agreement dated November 2005 contains two financial maintenance covenants. The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2009, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC is limited to borrowing $653 million, which can consist of additional draws against its revolving credit facilities or additional indebtedness.

~~So long~~

All other financial covenants contained in SPPC’s revolving credit facility and financing agreements are suspended, as SPPC’s senior secured debt ~~containing financial covenants remains~~is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by ~~both~~either Moody’s ~~and~~or S&P, SPPC would again be subject to the ~~restrictions contained in those debt agreements are suspended. However,~~limitations on indebtedness under these covenants.

Furthermore, SPPC may be subject to NVE’s cap on additional consolidated indebtedness. See NVE’s Ability to Issue Debt. As of March 31, 2009, SPPC’s own covenant restriction of $652.7 million is ~~limited by SPR’s~~less restrictive than NVE’s cap on additional consolidated indebtedness of ~~$665 million. Notwithstanding this restriction under~~$281.5. As such, SPPC is limited by NVE’s cap on additional indebtedness of $281.5 million, which includes the terms of SPR’s debt, in addition to this amount, SPPC would also be permitted to incur debt, including, but not limited to obligations incurred to finance property construction or improvements, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to its integrated resource plan. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

Ability to Issue General and Refunding Mortgage Securities

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

~~Table~~The Indenture creates a lien on substantially all of ~~Contents~~

SPPC’s properties in Nevada and California. As of ~~September 30, 2008,~~March 31, 2009, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue ~~an additional $539~~$613.1 million of General and Refunding Mortgage Securities as of ~~September 30, 2008.~~March 31, 2009. That amount is determined on the basis of:

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

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

SPPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its ~~General and Refunding Mortgage~~ Indenture, it will reduce the amount of securities issuable under ~~that indenture. See~~ the ~~2007 Form 10-K for additional information.~~Indenture.

Cross Default Provisions

None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by ~~SPR~~NVE or the other Utility under any of their respective financing agreements. Certain of ~~SPR’s~~NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by ~~SPR~~NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of ~~SPR~~NVE 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~~NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

Energy Supplier Matters

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC and SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of March 31, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $186.6 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 5, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty, if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade, the maximum collateral requirement would be $11.5 million.

Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s and S&P senior unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities senior unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of March 31, 2009, the maximum amount of collateral the Utilities would be required to post under these agreements is approximately $313.1 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $171.3 million would be required if the Utilities are downgraded one level and an additional amount of approximately $141.8 million would be required if the Utilities are downgraded two levels.

~~Pension Plans~~

Due to recent market conditions and the decline in the fair value of pension plan assets, the funding status of our pension plan in 2009 is likely to deteriorate as compared to 2008. The final determination of pension plan contributions for 2009 and future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We believe that we have adequate liquidity to meet our pension plan funding obligations for 2009.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC ~~recognized~~incurred a net ~~income~~loss of ~~$124.3~~$35.2 million ~~during~~for the three months ended ~~September 30, 2008~~March 31, 2009 compared to net income of ~~$133.1~~$8.0 million for the same period in ~~2007. During the nine months ended September 30, 2008,~~2008.

As of March 31, 2009, NPC ~~recognized net income of approximately $165.5 million compared to net income of approximately $161.3 million for the same period in 2007.~~

~~During the nine months ended September 30, 2008, NPC~~had paid ~~$54.9~~$22 million in dividends to ~~SPR.~~NVE. On April 30, 2009, NPC declared an additional dividend of $40 million.

Gross margin is presented by NPC in order to provide information 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 a key factor 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 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. ~~For reconciliation to operating income, see Note 2, Segment information in the Condensed Notes to Financial Statements.~~ Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

~~Table of Contents~~

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

Three Months Ended September 30, Nine Months Ended September 30,
Change from Change from
2008 2007 Prior Year % 2008 2007 Prior Year %
Operating Revenues:
     Electric $ 826,825 $ 894,226 -7.5 % $ 1,866,220 $ 1,887,499 -1.1 %

Energy Costs:
     Purchased power 319,324 313,487 1.9 % 577,161 584,797 -1.3 %
     Fuel for power generation 240,027 166,284 44.3 % 613,968 471,142 30.3 %
     Deferral of energy costs-net (80,191 ) 54,868 -246.2 % (44,107 ) 149,531 -129.5 %
$ 479,160 $ 534,639 -10.4 % $ 1,147,022 $ 1,205,470 -4.8 %

Gross Margin $ 347,665 $ 359,587 -3.3 % $ 719,198 $ 682,029 5.4 %

~~Gross margin decreased~~ for the three months ended ~~September 30, 2008~~March 31 were (dollars in thousands):

	Three Months Ended March 31,
	2009		2008		Change from Prior Year
Operating Revenues:
Electric	$	436,529	$	469,172		-7.0	%

Energy Costs:
Fuel for power generation		154,062		164,021		-6.1	%
Purchased power		88,206		93,750		-5.9	%
Deferral of energy costs - net		38,190		45,775		-16.6	%
	$	280,458	$	303,546		-7.6	%


Gross Margin	$	156,071	$	165,626		-5.8	%

Gross margin decreased in the first quarter of 2009, compared to the same period in ~~2007~~2008, primarily due to a decrease in customer usage due to cooler weather and a change in customer usage patterns, partially offset by an increase in customer growth. Gross margin increased for the nine months ended September 30, 2008 compared to the same period in 2007 primarily ~~due to an increase in Base Tariff General Rates (BTGR)~~ as a result of ~~NPC’s 2006 GRC, effective June 1, 2007~~milder winter weather, and ~~increased customer growth, partially~~the termination of various transmission service agreements. Partially offsetting these ~~increases~~decreases was a ~~decrease~~slight increase in average customer ~~usage primarily due to cooler weather.~~growth.

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

~~Electric Operating Revenue~~

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year
Electric Operating Revenues ($000):
Residential	$	191,370	$	205,378		-6.8	%
Commercial		96,794		104,512		-7.4	%
Industrial		128,039		133,013		-3.7	%
Retail revenues		416,203		442,903		-6.0	%
Other		20,326		26,269		-22.6	%
Total Revenues	$	436,529	$	469,172		-7.0	%

Retail sales in thousands
of MWhs		4,121		4,294		-4.0	%

Average retail revenue per MWh	$	101.00	$	103.14		-2.1	%

Three Months Ended September 30, Nine Months Ended September 30,
Change from Change from
2008 2007 Prior Year % 2008 2007 Prior Year %
Electric Operating Revenues:
Residential $ 435,986 $ 475,201 -8.3 % $ 887,173 $ 921,510 -3.7 %
Commercial 134,391 147,821 -9.1 % 362,850 365,854 -0.8 %
Industrial 228,141 242,963 -6.1 % 537,930 535,309 0.5 %
Retail revenues 798,518 865,985 -7.8 % 1,787,953 1,822,673 -1.9 %
Other 28,307 28,241 0.2 % 78,267 64,826 20.7 %
Total Revenues $ 826,825 $ 894,226 -7.5 % $ 1,866,220 $ 1,887,499 -1.1 %

Retail sales in thousands
Of megawatt-hours (MWh) 7,413 7,502 -1.2 % 16,952 17,283 -1.9 %

Average retail revenue per MWh $ 107.72 $ 115.43 -6.7 % $ 105.47 $ 105.46 0.0 %

NPC’s retail revenues decreased for the three ~~and nine~~ months ended ~~September 30, 2008 as~~March 31, 2009, compared to the same period in ~~2007~~2008, primarily due to decreases in ~~retail rates and decreases in~~ customer usage ~~due~~primarily as a result of milder winter weather and, to ~~cooler summer weather and~~a lesser extent, changes in customer usage ~~patterns.~~patterns, as well as decreases in retail rates. Retail rates decreased as a result of NPC’s various ~~Base Tariff~~BTER quarterly adjustments and Deferred Energy ~~Rate (BTER) quarterly cases~~Cases (see Note 3, Regulatory Actions inof the ~~condensed~~ Notes to the Financial ~~Statements)~~Statements in the 2008 Form 10-K). ~~Average~~Slightly offsetting these decreases were increases to the average number of residential, commercial and industrial customers ~~increased by~~of 0.6%, 0.4% and 3.3%, 2.5% and 4.6%, respectively for the three months ended September 30, 2008. Average residential, commercial, and industrial customers increased by 0.9%, 2.9% and 3.9%, respectively for the nine months ended September 30, 2008.

~~Electric Operating Revenues – Other was comparable for the three months ended September 30, 2008 compared to the same period in 2007.~~respectively.

Electric Operating Revenues – Other ~~increased~~decreased for the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007.~~2008. The ~~increase~~decrease is primarily due to the ~~elimination~~termination of ~~the reclassification of revenues associated with Mohave, as~~several transmission agreements, including a result of NPC’s 2006 GRC, which in 2007 were reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on Mohave refer to Note 1, Summary of Significant Accounting Policies in the Notes to Financial Statements in the 2007 Form 10-K. Also contributingtransmission agreement related to the ~~increase~~Higgins Generating Station which was ~~transmission related revenue as a result of the Calpine settlement, as discussed further~~purchased in ~~Note 5, Commitments and Contingencies.~~October 2008.

~~Table of Contents~~

Energy Costs

Energy Costs include ~~Purchased Power and~~ Fuel for ~~Generation.~~Generation and Purchased Power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of ~~purchased power versus~~ fuel for generation versus purchased power to meet demand can vary significantly. Factors that may affect energy costs include, but are not limited to:

·●

Weather

·●

Generation efficiency

·●

Plant outages

·●

Total system demand

·●

Resource constraints

·●

Transmission constraints

·●

Natural gas constraints

· ●

~~Long term~~

Long-term contracts; and

·●

Mandated power purchases

	Three Months Ended September 30,							Nine Months Ended September 30,							Three Months Ended March 31,
					Change from							Change from							Change from
	2008		2007		Prior Year %			2008		2007		Prior Year %			2009		2008		Prior Year

Energy Costs	$	559,351	$	479,771		16.6	%	$	1,191,129	$	1,055,939		12.8	%	$	242,268	$	257,771		-6.0	%
Total System Demand		7,723		7,841		-1.5	%		17,872		18,327		-2.5	%
Total System Demand (MWhs)																4,342		4,533		-4.2	%
Average cost per MWh	$	72.43	$	61.19		18.4	%	$	66.65	$	57.62		15.7	%	$	55.80	$	56.87		-1.9	%

~~For~~Energy costs, total system demand and the average cost per MWh decreased for the three ~~and nine~~ months ended ~~September 30, 2008, energy~~March 31, 2009, as compared to 2008. Energy costs and the average cost per MWh ~~increased~~decreased primarily due to ~~higher~~a decline in natural gas ~~prices.~~prices and an increase in self generation which was more economical than purchased power, partially offset by an increase in the settlement costs for hedging instruments. For the three months ended March 31, 2009, self generation represented approximately 83% of total system demand compared to approximately 74% for the same period in 2008. Total system demand decreased primarily due to a decrease in customer usage as a result of ~~cooler~~milder weather and a change in customer usage patterns.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Fuel for Power Generation	$	154,062	$	164,021		-6.1	%

Thousands of MWhs generated		3,607		3,337		8.1	%
Average cost per MWh of
Generated Power	$	42.71	$	49.15		-13.1	%

Fuel for power generation and the average cost per MWh decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to lower natural gas prices, which were partially offset by an increase in costs for the settlements of hedging instruments. Volume increased primarily due to the addition of the Higgins Generating Station in the fourth quarter of 2008.

Purchased Power

Three Months Ended September 30, Nine Months Ended September 30,
Change from Change from
2008 2007 Prior Year % 2008 2007 Prior Year %

Purchased Power $ 319,324 $ 313,487 1.9 % $ 577,161 $ 584,797 -1.3 %

Purchased Power in thousands
of MWhs 3,406 3,648 -6.6 % 6,435 7,200 -10.6 %
Average cost per MWh of
purchased power $ 93.75 $ 85.93 9.1 % $ 89.69 $ 81.22 10.4 %

	Three Months Ended March 31,
	2009		2008		Change from Prior Year
Purchased Power	$	88,206	$	93,750		-5.9	%

Purchased Power in thousands
of MWhs		735		1,196		-38.5	%
Average cost per MWh of
Purchased Power	$	120.01	$	78.39		53.1	%

Purchased power costs ~~increased~~decreased for the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007 primarily due to higher natural gas prices. Purchased power costs decreased for the nine months ended September 30,~~ 2008, ~~compared to the same period in 2007~~ primarily due to a decrease in ~~volume partially offset by higher natural gas prices.~~volume. MWhs decreased ~~for the three and nine months ended September 30, 2008 compared to the same period in 2007~~ primarily ~~due to~~as a result of an increase in ~~the reliance on internal~~self generation and a decrease in total system demand. The average cost per MWh of purchased power increased ~~for the three and nine months ended September 30, 2008~~significantly compared to ~~the same~~prior period ~~in 2007~~ primarily due to ~~higher natural~~an increase in the settlement costs for hedging instruments related to gas ~~prices partially offset by a decrease in fixed capacity charges and cost of hedging instruments.~~purchased for tolling contracts.

~~Fuel For Power Generation~~

Three Months Ended September 30, Nine Months Ended September 30,
Change from Change from
2008 2007 Prior Year % 2008 2007 Prior Year %

Fuel for power generation $ 240,027 $ 166,284 44.3 % $ 613,968 $ 471,142 30.3 %

Thousands of MWhs generated 4,317 4,193 3.0 % 11,437 11,127 2.8 %
Average fuel cost per MWh of
generated power $ 55.60 $ 39.66 40.2 % $ 53.67 $ 42.34 26.8 %

Fuel for power generation costs and the average cost per MWh increased for the three and nine months ended September 30, 2008 primarily due to higher natural gas prices partially offset by a decrease in the cost of hedging instruments. Volume increased for the three and nine months ended September 30, 2008 due to greater reliance on internal generation.

~~Table of Contents~~

Deferral of Energy Costs - Net

Three Months Nine Months
Ended September 30, Ended September 30,
2008 2007 Change from Prior Year % 2008 2007 Change from Prior Year %

Deferred energy costs - net $ (80,191 ) $ 54,868 -246.2 % $ (44,107 ) $ 149,531 -129.5 %

	Three Months Ended March 31,
	2009		2008		Change from Prior Year

Deferral of energy costs - net	$	38,190	$	45,775		-16.6	%

Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts ~~recovered~~recoverable through current rates. To the extent actual costs exceed amounts ~~recovered~~recoverable through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts ~~recovered~~recoverable through current rates, the difference is recognized as an increase in costs. Deferral of 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 ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ include amortization of deferred energy costs of ~~$37.7~~$8.2 million and ~~$73.0~~$39.8 million, respectively; and an ~~under-collection~~over-collection of amounts recoverable in rates of ~~$115.9~~$30 million in ~~2008~~2009 and ~~$18.2~~$6 million in 2007. Amounts for the nine months ended September 30, 2008 and 2007 include amortization of deferred energy costs of $123.9 million and $137.8 million, respectively; and an under-collection of amounts recoverable in rates of $168 million in 2008 and an over-collection of $11.8 million in 2007. Amortization for both the three and six month periods include amounts for the western energy crisis rate case and the reinstatement of deferred energy as discussed in Note 3, Regulatory Actions, of Notes to Financial Statements in NPC’s 2007 Form 10-K.2008.

Allowance for Funds Used During Construction ~~(AFUDC)~~

Three Months Ended September 30, Nine Months Ended September 30,
2008 2007 Change from Prior Year % 2008 2007 Change from Prior Year %

Allowance for other funds
used during construction $ 6,543 $ 4,701 39.2 % $ 21,093 $ 11,046 91.0 %

Allowance for borrowed funds used during construction $ 5,128 $ 3,936 30.3 % $ 16,503 $ 9,189 79.6 %
$ 11,671 $ 8,637 35.1 % $ 37,596 $ 20,235 85.8 %

	Three Months Ended March 31,
	2009		2008		Change from Prior Year

Allowance for other funds used during construction	$	5,621	$	6,858		-18.0	%

Allowance for borrowed funds used during construction		4,562		5,355		-14.8	%
	$	10,183	$	12,213		-16.6	%

AFUDC ~~increased~~decreased for the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007~~2008, primarily due to ~~an increase in Construction Work-In-Progress (CWIP) associated with~~ the completion of construction of the Clark Peaking ~~Units. One block was placed~~Units in ~~service in July~~late 2008, ~~and~~partially offset by the ~~remaining two blocks are scheduled for completion in~~construction of the ~~fourth quarter of 2008.~~500 MW natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011.

Other (Income) and Expenses

Three Months Ended September 30, Nine Months Ended September 30,
2008 2007 Change from Prior Year % 2008 2007 Change from Prior Year %

Other operating expense $ 69,432 $ 61,400 13.1 % $ 189,144 $ 167,401 13.0 %
Maintenance expense $ 12,469 $ 16,360 -23.8 % $ 42,727 $ 54,143 -21.1 %
Depreciation and amortization $ 37,902 $ 38,151 -0.7 % $ 120,855 $ 112,745 7.2 %
Interest charges on long-term debt $ 46,662 $ 41,955 11.2 % $ 129,283 $ 123,029 5.1 %
Interest charges-other $ 6,737 $ 5,876 14.7 % $ 17,952 $ 18,315 -2.0 %
Interest accrued on deferred energy $ (2,803 ) $ (4,573 ) -38.7 % $ (5,681 ) $ (11,849 ) -52.1 %
Carrying charge for Lenzie - - N/A - $ (16,080 ) N/A
Reinstated interest on deferred energy - - N/A - $ (11,076 ) N/A
Other income $ (4,116 ) $ (2,315 ) 77.8 % $ (12,970 ) $ (10,345 ) 25.4 %
Other expense $ 2,028 $ 1,346 50.7 % $ 5,045 $ 8,772 -42.5 %

	Three Months Ended March 31,
	2009			2008			Change from Prior Year

Other operating expense	$	70,193		$	57,095			23	%
Maintenance expense	$	27,534		$	16,650			65.4	%
Depreciation and amortization	$	52,363		$	40,630			28.9	%
Interest charges on long-term debt	$	52,308		$	40,997			27.6	%
Interest charges-other	$	7,297		$	5,831			25.1	%
Interest accrued on deferred energy	$	(1,853	)	$	(1,794	)		3.3	%
Other income	$	(2,342	)	$	(5,747	)		-59.2	%
Other expense	$	3,207		$	1,361			135.6	%

Other operating expense increased for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, primarily due to ~~an increase in reserves for uncollectible accounts of approximately $4.5 million, change in account classifications of chemical costs from maintenance expense in 2007 to operating expense in 2008,~~ costs associated with renewable energy programs, increased pension and other post retirement expenses, and operating expenses for the ~~recently approved Union contract, partially offset by~~ ~~billing adjustments during the period to NPC’s operating partner for Reid Gardner IV.~~Higgins Generating Station acquired in October 2008.

~~Other operating~~Maintenance expense increased for the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007, primarily~~2008, due to the ~~reversal of a reserve established for Enron legal fees in 2007. In March 2007, the PUCN granted recovery of these expenses, see Note 3, Regulatory Actions,~~addition of the ~~Notes to Financial Statements in~~Higgins Generating Station and scheduled maintenance at the 2007 Form 10-K for further discussion. Additionally, in 2007 certain consulting fees were reclassified to regulatory asset reducing expense in 2007. Also contributing to the increase in other operating expenses were increased costs for regulatory amortizations in 2008 as compared to the same period in 2007, as well as an increase in reserves for uncollectible accountsClark, Navajo and ~~other factors as mentioned above.~~

~~Table of Contents~~

Maintenance expense decreased for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to billing adjustments during the period to NPC’s operating partner for Reid Gardner IV, partially offset by a change in account classification of chemical costs from maintenance expense in 2007 to operating expense in 2008.

~~Maintenance expense decreased for the nine months ended September 30, 2008, compared to the same period in 2007 due to planned maintenance costs for Lenzie and a forced outage at Harry Allen in 2007.~~

Depreciation and amortization expenses decreased during the three months ended September 30, 2008, compared to the same periods in 2007, primarily as a result of a deferred tax adjustment for the Temporary Renewable Energy Development trust (“TRED trust”) partially offset by increases to plant-in-service.Silverhawk Generating Stations.

Depreciation and amortization expenses increased during the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same ~~periods~~period in ~~2007, primarily~~2008, as a result of ~~depreciation expense related~~additions to ~~Lenzie, beginning June 2007 as a result~~plant-in-service. Plant-in-service increased primarily due to the completion of ~~NPC’s 2006 GRC. The increase was partially offset by~~ the ~~deferred tax adjustment discussed above.~~Clark Peaking Units and the addition of the Higgins Generating Station in the latter part of 2008.

Interest charges on Long-Term Debt ~~increased~~ for the three ~~and nine~~ months ended ~~September 30, 2008, as~~March 31, 2009, compared to the same period in ~~2007,~~2008 increased primarily due to the issuance of ~~$500 million Series S General and Refunding Mortgage Notes in July 2008 and higher~~$1.1 billion additional debt used to fund significant capital expenditures. This increase was partially offset by lower interest ~~rates~~ on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the ~~2007~~2008 Form 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 ~~increased~~ for the three months ended ~~September 30, 2008, as~~March 31, 2009, compared to the same period in ~~2007,~~2008 increased due to interest expense associated with refunds for construction advances in 2008. Interest charges-other decreased for the nine months ended September 30, 2008, as compared to the same period in 2007, due to lower interest associated with customer transmission deposits, partially offset by interest expense associated with refunds for construction advances,on taxes and higher amortization costs related to new debt issues and ~~interest expense related to new leases in 2008.~~redemptions.

Interest accrued on deferred energy costs ~~decreased~~ for the three months ended ~~September 30, 2008, as~~March 31, 2009 compared to the same period in ~~2007, due to lower deferred energy balances. Interest accrued on deferred energy costs decreased~~2008 did not change significantly.

Other income for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007~~2008 decreased primarily due to lower deferred energy balances, partially offset by carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007. 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~~income earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in ~~rates. See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2007 Form 10-K for discussion of the accounting for the carrying charge for Lenzie.~~

~~Reinstated interest on deferred energy represents the carrying charges which were previously expensed~~2008 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. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2007 Form 10-K.

Other income increased during the three months ended September 30, 2008, as compared to the same period in 2007 primarily due to carrying charges on energy conservation programs. Other income increased during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to carrying charges on energy conservation programs and the gain from the settlement with Calpine, and the subsequent gain on sale of the stock received, as discussed further in Note 6,13, Commitments and Contingencies in ~~the Consolidated Notes to Financial Statements. This income was partially offset by lower interest income in 2008.~~

Other expense increased during the three months ended September 30, 2008, as compared to the same period in 2007, due to higher advertising costs in 2008. Other expense decreased during the nine months ended September 30, 2008, as compared to the same period in 2007, due to costs in 2007 associated with the Energy Savings Project for the Clark County School District, as agreed upon in the Reid Gardner Consent Decree discussed in ~~Note 13, Commitments and Contingencies of~~ the Notes to Financial Statements in the ~~2007~~2008 Form 10-K. Also contributing to the decrease in other income was the expiration of the amortization of gains associated with the disposition of property and lower interest income. This decrease was partially offset by higher carrying charges on energy conservation programs in 2009.

~~ANALYSIS OF CASH FLOWS~~

~~Cash flows increased during~~Other expense for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007~~2008 increased primarily due to ~~a decrease~~the write-off of permitting costs.

ANALYSIS OF CASH FLOWS

Cash flows increased during the three months ended March 31, 2009 compared to the same period in ~~cash used for investing activities and~~2008 primarily due to an increase in cash from financing activities partially offset ~~partially~~ by a decrease in cash from operating activities.

~~Table of Contents~~

Cash ~~From~~Used By Operating ~~Activities~~Activities. . The decrease in cash from operating activities was primarily due ~~primarily~~ to ~~increases~~lower revenues as a result of milder weather and to a lesser extent, changes in ~~energy costs~~customer usage patterns. Also contributing to the decrease in ~~excess of the energy revenue collected in rates,~~cash from operating activities was an increase in ~~expenditures~~costs for ~~conservation programs, site studies~~operations and ~~other regulatory activities~~maintenance costs for generating facilities, the funding of approximately $20 million for pension plans, prepayments for land leases and in 2008, ~~and~~NPC received a significant prepayment ~~of tax obligations. The decrease was partially offset by the settlement with Calpine, a reduction in funding~~ for ~~retirement plans and prepaid~~ transmission ~~revenue.~~services.

Cash Used By Investing ~~Activities~~Activities. . Cash used byfor investing activities ~~decreased primarily due to~~did not change significantly between the ~~closing stages of major construction activity for the peaking units at Clark Station, which began in 2007, and a reduction in construction for infrastructure.~~periods.

Cash From Financing ~~Activities~~Activities. . Cash from financing activities increased primarily due to the ~~proceeds from the~~ issuance of ~~$500~~approximately $625 million ~~of 6.5% General and Refunding Mortgage Notes, Series S, due 2018 and~~in new debt, partially offset by payments on the revolving credit facility. This increase was partially offset by an investment of ~~$133~~approximately $53 million by ~~SPR, partially offset by higher dividends paid to SPR.~~NVE in 2008.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is 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, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.

Available Liquidity as of September 30, 2008 (in millions)

Cash and Cash Equivalents $ 177.7
Balance available on Revolving Credit Facility (1)(2)
$ 585.4

$ 763.1

~~(1)~~ ~~The available balance reflects management's estimate of a reduction of approximately $11 million as a result of the bankruptcy of a lending bank.~~

~~(2)~~ ~~As of November 4, 2008, NPC had approximately $232.2 million available under its revolving credit facility.~~

As of March 31, 2009, NPC had cash on hand of approximately $81.6 million. NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as ~~United States~~U.S. treasury bills. In addition to cash on hand, ~~and the revolving credit facility,~~ NPC may issue debt up to ~~$665~~$281.5 million, on a consolidated basis, ~~subject to certain limitations discussed below.~~

~~For~~which includes the ~~nine months ended September 30, 2008, SPR contributed capital to NPC~~use of approximately ~~$133~~$268.0 million ~~for general corporate purposes. For~~of the ~~nine months ended September 30, 2008, NPC paid dividends to SPR of $54.9 million.~~

Utilities’ revolving credit facilities. NPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that itcash on hand, internally generated funds and the ability to issue debt, which includes the use of the NPC’s revolving credit facility, will be ~~able~~sufficient to meet short-term operating costs. However, if energy costs ~~such as~~rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs ~~with internally generated funds, including~~are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the ~~recovery~~posting of ~~deferred energy~~collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, re-finance debt or obtain funding through an equity issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the ~~use~~Utilities. As a result of ~~its~~these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities may not be able to fully utilize the availability on their revolving credit ~~facility. To manage liquidity needs~~facilities. NVE and the Utilities are projecting that their ability to issue debt will increase in the second and third quarter of 2009, as the Utilities’ operating income typically increases during this time period, and new rates as a result of ~~seasonal peaks~~NPC’s GRC are expected to be in ~~fuel requirements,~~ effect beginning July 1, 2009.

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

1-08788	~~SIERRA PACIFIC RESOURCES~~NV ENERGY, INC.	88-0198358	Nevada
	~~P.O. Box 10100~~6226 West Sahara Avenue
	~~(6100 Neil Road)~~Las Vegas, Nevada 89146
	~~Reno, Nevada 89520-0400 (89511)~~
	~~(775) 834-4011~~(702) 402-5000

2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) ~~367-5000~~402-5000

0-00508	SIERRA PACIFIC POWER COMPANY d/b/a	88-0044418	Nevada
	NV ENERGY
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

~~Sierra Pacific Resources:~~NV Energy, Inc.:	Large accelerated filerþ	Accelerated filero	Non-accelerated filer o	Smaller reporting company o
Nevada Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filer þ	Smaller reporting company o
Sierra Pacific Power Company:	Large accelerated filero	Accelerated filero	Non-accelerated filer þ	Smaller reporting company o


Class		Outstanding at ~~October 31, 2008~~April 30, 2009
Common Stock, $1.00 par value of ~~Sierra Pacific Resources~~NV Energy, Inc.		~~234,149,821~~ 234,395,695Shares

Acronyms and Terms...................................................................................................................................................................................		3

PART I - FINANCIAL INFORMATION

ITEM 1.	Financial Statements

~~PART I — FINANCIAL INFORMATION~~ NV Energy, Inc.

	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008…………...……...……………...................................................................	4
	Consolidated Statements of Operations – Three Months Ended March 31, 2009 and 2008…………………………………………………........	5
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008………………….......................................................	6

~~ITEM 1. Financial Statements~~ Nevada Power Company -

	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008…………...……...……………...................................................................	7
	Consolidated Statements of Operations – Three Months Ended March 31, 2009 and 2008………………………………………………….........	8
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008…………………........................................................	9

Sierra Pacific Power Company -


~~Sierra Pacific Resources —~~
Consolidated Balance Sheets ~~— September 30, 2008~~– March 31, 2009 and December 31, 2007 2008…………...……...…………......................................................................	10
	Consolidated Statements of Income – Three Months Ended March 31, 2009 and 2008……………………………………………………...........	3 11

~~Consolidated Income Statements — Three Months and Nine Months Ended September 30, 2008 and 200~~7		4
Consolidated Statements of Cash Flows ~~— Nine~~– Three Months Ended ~~September 30, 2008~~March 31, 2009 and ~~200~~7 2008………………………………………………...........	12
	5
	Condensed Notes to Consolidated Financial Statements………………………………………………………………………………….................	13

~~Nevada Power Company —~~
~~Consolidated Balance Sheets — September~~ ~~30, 2008 and December 31, 2007~~		6
~~Consolidated Income Statements — Three Months and Nine Months Ended September 30, 2008~~ ~~and 200~~7		7
~~Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2008~~ ~~and 200~~7		8

~~Sierra Pacific Power Company —~~
~~Consolidated Balance Sheets — September~~ ~~30, 2008 and December 31, 2007~~		9
~~Consolidated Income Statements — Three Months and Nine Months Ended September 30, 2008~~ ~~and 200~~7		10
~~Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2008~~ ~~and 200~~7		11

~~Condensed Notes to Consolidated Financial Statements~~		12

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations~~Operations………………………………………………........	26

28	NV Energy, Inc.……………..…………………………………………….…………………………….............................................................................	30
	Nevada Power Company …………………………………………………….………………………………………………………...............................	36
	Sierra Pacific Power Company ………………………………………………………………………………………………………...............................	43

ITEM 3A.	Quantitative and Qualitative Disclosures about Market Risk………………………………………………………………………………...............	52

ITEM 4 and 4T.	Controls and Procedures……………………………………………………………………………………………………………………....................	52

~~Sierra Pacific Resources~~ PART II - OTHER INFORMATION
	34
~~Nevada Power Company~~ ITEM 1.	Legal Proceedings…………………………………………………………………………...……………..........................................................................	53
	38
ITEM 1A.	~~Sierra Pacific Power Company~~Risk Factors…………………………………………………………………………………………………………………………..................................	53

45 ITEM 2.	Unregistered Sales of Equity Securities and use of Proceeds......................................................................................................................................	53

ITEM 3.	Defaults Upon Senior Securities........................................................................................................................................................................................	53

ITEM 4.	Submission of Matters to a Vote of Security Holders....................................................................................................................................................	53

ITEM 5.	Other Information.................................................................................................................................................................................................................	54

ITEM 6.	Exhibits..................................................................................................................................................................................................................................	55

Signature Page and Certifications..................................................................................................................................................................................................................		56

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED ~~September 30, 2008~~March 31, 2009

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

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)

~~ITEM 3.~~ ~~Quantitative and Qualitative Disclosures about Market Risk~~ Acronyms/Terms		55	Meaning

2008 Form 10-K	NVE’s NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2008
~~ITEM 4 and 4T.~~ ~~Controls and Procedures~~ AFUDC		55	Allowance for Funds Used During Construction or Allowance for Borrowed Funds Used During Construction
APB 28-1			Accounting Principles Board 28-1, “Interim Financial Reporting”
~~PART II — OTHER INFORMATION~~BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
~~ITEM 1.~~ ~~Legal Proceedings~~ Clark Generating Station		56	550 megawatt nominally rated William Clark Generating Station
~~ITEM 1A.~~ ~~Risk Factors~~ Clark Peaking Units		56	600 megawatt nominally rated peaking units at the William Clark Generating Station
~~ITEM 2.~~ ~~Unregistered Sales of Equity Securities and Use of Proceeds~~CPUC		56	California Public Utilities Commission
~~ITEM 3.~~ ~~Defaults Upon Senior Securities~~CWIP		56	Construction Work-In-Progress
~~ITEM 4.~~ ~~Submission of Matters to a Vote of Security Holders~~ DBRS		56	Dominion Bond Rating Service
~~ITEM 5.~~ ~~Other Information~~ DEAA		56	Deferred Energy Accounting Adjustment
~~ITEM 6.~~ ~~Exhibits~~ DOS		57	Distribution Only Service
DSM			Demand Side Management
~~Signature Page and Certifications~~ Dth	Decatherm	58
EEC	Ely Energy Center
EPS	Earnings Per Share
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd.
FSP 107-1	FASB Staff Position No. 107-1, “Interim Disclosure about Fair Value of Financial Instruments”
FSP 157-2	FASB Staff Position No. 157-2, “Defers the effective date for certain portions of SFAS 157 related to nonrecurring measurement of nonfinancial assets and liabilities”
FSP 157-4	FASB Staff Position No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that are not Orderly”
GAAP	Accounting Principles Generally Accepted in the United States
GRC	General Rate Case
Higgins Generating Station	598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP	Integrated Resource Plan
Moody’s	Moody’s Investors Services, Inc.
MW	Megawatt
MWh	Megawatt hour
NEICO	Nevada Electrical Investment Company
NPC	Nevada Power Company d/b/a NV Energy
NVE	NV Energy, Inc.
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC	Portfolio Energy Credit
Portfolio Standard	Renewable Energy Portfolio Standard
PUCN	Public Utilities Commission of Nevada
ROE	Return on Equity
ROR	Rate of Return
S&P	Standard and Poor’s
Salt River	Salt River Project
SEC	Securities and Exchange Commission
SFAS 71	Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 128	Statement of Financial Accounting Standards No. 128, "Earnings Per Share"
SFAS 131	Statement of Financial Accounting Standards No. 131, "Disclosure About Segments of an Enterprise and Related Information"
SFAS 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 138	Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133"
SFAS 144	Statement of Financial Accounting Standards No. 144, “Accounting for the Disposal or Impairment of Long-Lived Assets”
SFAS 149	Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
SFAS 155	Statement of Financial Accounting Standards No. 155, "Accounting for Certain Hybrid Financial Instruments - An Amendment of FASB Statements No. 133 and 140"
SFAS 157	Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”
SFAS 158	Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS 161	Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activity”
SPPC	Sierra Pacific Power Company d/b/a NV Energy
TMWA	Truckee Meadows Water Authority
Tracy Generating Station	541 megawatt nominally rated Frank A. Tracy Generating Station
U.S.	United States of America
WSPP	Western Systems Power Pool

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

		September 30,		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	9,278,831	$	8,468,711
Less accumulated provision for depreciation			2,607,546		2,526,379
			6,671,285		5,942,332
Construction work-in-progress			790,970		1,068,666
			7,462,255		7,010,998

Investments and other property, net			31,037		31,061

Current Assets:
Cash and cash equivalents			229,145		129,140
Accounts receivable less allowance for uncollectible accounts:
	2008- $33,823, 2007-$36,061		528,443		434,359
Deferred energy costs - electric (Note 1)			43,509		75,948
Materials, supplies and fuel, at average cost			130,164		117,483
Risk management assets (Note 5)			17,387		22,286
Deferred income taxes			82,951		43,295
Other			41,903		45,909
			1,073,502		868,420
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 1)			291,223		205,030
Regulatory tax asset			267,445		267,848
Regulatory asset for pension plans			185,295		133,984
Other regulatory assets			777,568		758,287
Risk management assets (Note 5)			8,893		12,429
Risk management regulatory assets - net (Note 5)			210,346		26,067
Unamortized debt issuance costs			64,494		65,218
Other			158,272		85,408
			1,963,536		1,554,271
TOTAL ASSETS		$	10,530,330	$	9,464,750
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,156,607	$	2,996,575
Long-term debt			4,793,078		4,137,864
			7,949,685		7,134,439
Current Liabilities:
Current maturities of long-term debt			9,794		110,285
Accounts payable			348,898		357,867
Accrued interest			75,970		69,485
Accrued salaries and benefits			38,664		35,020
Current income taxes payable			-		3,544
Risk management liabilities (Note 5)			185,759		39,509
Accrued taxes			8,378		8,336
Deferred energy costs - electric (Note 1)			3,950		17,573
Deferred energy costs - gas (Note 1)			10,869		11,369
Other current liabilities			89,150		65,991
			771,432		718,979
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			982,987		852,630
Deferred investment tax credit			26,665		28,895
Regulatory tax liability			26,273		28,445
Customer advances for construction			89,108		100,125
Accrued retirement benefits			121,872		77,525
Risk management liabilities (Note 5)			35,201		7,369
Regulatory liabilities			326,518		304,026
Other			200,589		212,317
			1,809,213		1,611,332
TOTAL CAPITALIZATION AND LIABILITIES		$	10,530,330	$	9,464,750

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

	September 30, 2008
Description	NPC Electric			SPPC Electric			SPPC Gas			SPR Total

Unamortized balances approved for collection in current rates
as of January 1, 2008	$	79,924		$	13,257		$	(1,208	)	$	91,973
Balances approved in 2008 DEAA(1)(2)		(44,424	)		(34,300	)		(10,174	)		(88,898	)
Cumulative Balance request in 2008 DEAA		35,500			(21,043	)		(11,382	)		3,075
2008 amortization of approved balances		(89,653	)		(13,098	)		983			(101,768	)
2008 deferred energy costs not yet requested		175,056			29,267			(470	)		203,853
Western Energy Crisis Rate Case (effective 6/07, 3 years)		46,711			-			-			46,711
Reinstatement of deferred energy (effective 6/07, 10 years)		167,118			-			-			167,118
Cumulative CPUC balance (3)		-			924			-			924
Total	$	334,732		$	(3,950	)	$	(10,869	)	$	319,913

Current Assets
Deferred energy costs – electric	$	43,509		$	-		$	-		$	43,509
Deferred Assets
Deferred energy costs - electric		291,223			-			-			291,223
Current Liabilities
Deferred energy costs – electric		-			(3,950	)		-			(3,950	)
Deferred energy costs – gas		-			-			(10,869	)		(10,869	)
Total	$	334,732		$	(3,950	)	$	(10,869	)	$	319,913


Nine Months Ended	NPC			SPPC			SPPC			SPPC			SPR			SPR
September 30, 2008	Electric			Electric			Gas			Total			Other			Consolidated
Operating Revenues	$	1,866,220		$	758,612		$	137,125		$	895,737		$	19		$	2,761,976

Energy Costs:
Purchased power		577,161			251,474			-			251,474			-			828,635
Fuel for power generation		613,968			211,137			-			211,137			-			825,105
Gas purchased for resale		-			-			108,288			108,288			-			108,288
Deferred energy costs - net		(44,107	)		(12,572	)		(2,296	)		(14,868	)		-			(58,975	)
		1,147,022			450,039			105,992			556,031			-			1,703,053

Gross Margin	$	719,198		$	308,573		$	31,133		$	339,706		$	19		$	1,058,923


Other		189,144									103,744			2,521			295,409
Maintenance		42,727									22,204			-			64,931
Depreciation and amortization		120,855									64,801			-			185,656
Taxes:
Income taxes		69,592									24,213			(11,110	)		82,695
Other than income		24,015									16,128			123			40,266

Operating Income	$	272,865								$	108,616		$	8,485		$	389,966

	NPC			SPPC		SPR Holding Co. and Other Subs.		SPR Consolidated
2008	$	(119	)	$	539	$	-	$	420
2009		7,218			600		-		7,818
2010		8,004			-		-		8,004
2011		369,924			-		-		369,924
2012		136,448			100,000		63,670		300,118
		521,475			101,139		63,670		686,284
Thereafter		2,475,506			1,183,250		460,539		4,119,295
		2,996,981			1,284,389		524,209		4,805,579
Unamortized Premium(Discount) Amount		(13,124	)		9,617		800		(2,707	)
Total	$	2,983,857		$	1,294,006	$	525,009	$	4,802,872

	September 30, 2008 Fair Value Level 2									December 31, 2007 Fair Value
	SPR			NPC			SPPC			SPR			NPC			SPPC

Risk management assets- current	$	17.3		$	12.8		$	4.5		$	22.3		$	16.1		$	6.2
Risk management assets- noncurrent		8.9			6.5			2.4			12.5			9.1			3.4
Total risk management assets		26.2			19.3			6.9			34.8			25.2			9.6

Risk management liabilities- current		185.8			132.5			53.3			39.5			27.0			12.5
Risk management liabilities- noncurrent		35.2			22.6			12.6			7.4			5.1			2.3
Total risk management liabilities		221.0			155.1			65.9			46.9			32.1			14.8

Less prepaid electric and gas options		15.6			11.2			4.4			13.9			10.2			3.7

Risk management regulatory assets/liabilities – net(1)	$	(210.4	)	$	(147.0	)	$	(63.4	)	$	(26.0	)	$	(17.1	)	$	(8.9	)

Sierra Pacific Resources, consolidated

	For The Three Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	5,237		$	5,725		$	641		$	268
Interest cost		10,677			9,855			2,683			2,570
Expected return on plan assets		(11,463	)		(10,474	)		(2,088	)		(1,309	)
Amortization of prior service cost		(265	)		407			(257	)		30
Amortization of net (gain)/loss		1,980			1,803			872			242
Amortization of Transition Obligation		-			-			-			815

Net periodic benefit cost	$	6,166		$	7,316		$	1,851		$	2,616


	For The Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007

Service cost	$	16,506		$	17,175		$	1,922		$	1,804
Interest cost		32,142			29,565			8,049			7,711
Expected return on plan assets		(35,587	)		(31,422	)		(6,264	)		(3,927	)
Amortization of prior service cost		25			1,222			(771	)		91
Amortization of net (gain)/loss		4,733			5,409			2,617			2,444
Amortization of Transition Obligation		-			-			-			727

Net periodic benefit cost	$	17,819		$	21,949		$	5,553		$	8,850

	Three Months								Nine Months
	Ended September 30,								Ended September 30,
	2008			2007		Change from Prior Year %			2008			2007		Change from Prior Year %

Deferred energy costs - net	$	(80,191	)	$	54,868		-246.2	%	$	(44,107	)	$	149,531		-129.5	%

Available Liquidity as of September 30, 2008 (in millions)

Cash and Cash Equivalents	$	177.7
Balance available on Revolving Credit Facility (1)(2)	$	585.4

	$	763.1

Available Liquidity as of September 30, 2008 (in millions)
Cash and Cash Equivalents	$	29.3
Balance available on Revolving Credit Facility (1)(2)	$	313.2

	$	342.5

		Expected Maturity Date
									Fair
		2008	2009	2010	2011	2012	Thereafter	Total	Value
Long-term Debt
	SPR
	Fixed Rate	$ -	$ -	$ -	$ -	$ 63,670	$ 460,539	$ 524,209	$ 505,281
	Average Interest Rate	-	-	-	-	7.80%	7.77%	7.77%

	NPC
	Fixed Rate	$ -	$ -	$ -	$ 364,000	$ 130,000	$2,269,335	$2,763,335	$2,569,160
	Average Interest Rate	-	-	-	8.14%	6.50%	6.35%	6.60%
	Variable Rate	$ -	$ -	$ -	$ -	$ -	$ 179,500	$ 179,500	$ 179,500
	Average Interest Rate	-	-	-	-	-	5.88%	5.88%

	SPPC
	Fixed Rate	$ 539	$ 600	$ -	$ -	$ 100,000	$ 875,000	$ 976,139	$ 919,696
	Average Interest Rate	6.40%	6.40%	-	-	6.25%	6.12%	6.13%
	Variable Rate	$ -	$ -	$ -	$ -	$ -	$ 308,250	$ 308,250	$ 308,250
	Average Interest Rate	-	-	-	-	-	5.57%	5.57%

	Total Debt	$ 539	$ 600	$ -	$ 364,000	$ 293,670	$4,092,624	$ 4,751,433	$4,481,887


	Sierra Pacific Resources		d/b/a NV Energy
	(Registrant)

Date: ~~November~~May 4, ~~2008~~2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: ~~November~~May 4, ~~2008~~2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Nevada Power Company d/b/a NV Energy
	(Registrant)

Date: May 4, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: May 4, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)

	~~Nevada Power Company d/b/a~~ ~~NV Energy~~
	~~(Registrant)~~

Date: ~~November~~May 4, ~~2008~~2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: ~~November~~May 4, ~~2008~~2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)



	~~Sierra Pacific Power Company d/b/a~~ ~~NV Energy~~
	~~(Registrant)~~

~~Date: November 4, 2008~~	~~By:~~	~~/s/ William D. Rogers~~
		~~William D. Rogers~~
		~~Chief Financial Officer~~
		~~(Principal Financial Officer)~~

~~Date: November 4, 2008~~	~~By:~~	~~/s/ E. Kevin Bethel~~
		~~E. Kevin Bethel~~
		~~Chief Accounting Officer~~
		~~(Principal Accounting Officer)~~