NEVADA POWER CO - FORM 10-Q

Attached files

file	filename
EX-32.3 - EXHIBIT 32.3 - NEVADA POWER CO	exhibi32-3.htm
EX-32.5 - EXHIBIT 32.5 - NEVADA POWER CO	exhibit32-5.htm
EX-10.1 - EXHIBIT 10.1 - NEVADA POWER CO	exhibit10-1.htm
EX-31.4 - EXHIBIT 31.4 - NEVADA POWER CO	exhibit31-4.htm
EX-12.1 - EXHIBIT 12.1 - NEVADA POWER CO	exhibit12-1.htm
EX-31.3 - EXHIBIT 31.3 - NEVADA POWER CO	exhibit31-3.htm
EX-32.4 - EXHIBIT 32.4 - NEVADA POWER CO	exhibit32-4.htm
EX-31.1 - EXHIBIT 31.1 - NEVADA POWER CO	exhibit31-1.htm
EX-31.5 - EXHIBIT 31.5 - NEVADA POWER CO	exhibit31-5.htm
EX-32.1 - EXHIBIT 32.1 - NEVADA POWER CO	exhibit32-1.htm
EX-31.6 - EXHIBIT 31.6 - NEVADA POWER CO	exhibit31-6.htm
EX-12.2 - EXHIBIT 12.2 - NEVADA POWER CO	exhibit12-2.htm
EX-32.2 - EXHIBIT 32.2 - NEVADA POWER CO	exhibit32-2.htm
EX-31.2 - EXHIBIT 31.2 - NEVADA POWER CO	exhibit31-2.htm
EX-32.6 - EXHIBIT 32.6 - NEVADA POWER CO	exhibit32-6.htm
EX-12.3 - EXHIBIT 12.3 - NEVADA POWER CO	exhibit12-3.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2010

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

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

1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(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) 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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes______ No (Response applicable to all registrants)

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

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

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

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

Class		Outstanding at April 30, 2010
Common Stock, $1.00 par value of NV Energy, Inc.		234,939,325 Shares

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.

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

Table of Contents

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2010

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
Acronyms & Terms			3

ITEM 1.	Financial Statements

	NV Energy, Inc.
		Consolidated Income Statements – Three Months Ended March 31, 2010 and 2009	4
		Consolidated Balance Sheet – March 31, 2010 and December 31, 2009	5
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009	7
	Nevada Power Company
		Consolidated Income Statements – Three Months Ended March 31, 2010 and 2009	8
		Consolidated Balance Sheet – March 31, 2010 and December 31, 2009	9
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009	11
	Sierra Pacific Power Company
		Consolidated Income Statements – Three Months Ended March 31, 2010 and 2009	12
		Consolidated Balance Sheet – March 31, 2010 and December 31, 2009	13
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009	15
	Condensed Notes to Financial Statements
		Note 1. Summary of Significant Accounting policies	16
		Note 2. Segment Information	17
		Note 3. Regulatory Actions	18
		Note 4. Long-Term Debt	19
		Note 5. Fair Value of Financial Instruments	20
		Note 6. Derivatives and Hedging Activities	20
		Note 7. Retirement Plan and Post-Retirement Benefits	23
		Note 8. Commitments and Contingencies	24
		Note 9. Earnings Per Share (NVE)	26
		Note 10. Assets Held for Sale	26
		Note 11. Subsequent Events	27

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

	NV Energy, Inc.		34
	Nevada Power Company		38
	Sierra Pacific Power Company		45

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		54

ITEM 4 and 4T.	Controls and Procedures		55

PART II – OTHER INFORMATION

ITEM 1.	Legal Proceedings		55
ITEM 1A.	Risk Factors		56
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		56
ITEM 3.	Defaults Upon Senior Securities		56
ITEM 5.	Other Information		56
ITEM 6.	Exhibits		57

Signature Page and Certifications			58

Table of Contents

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

Acronym/Term		Meaning

2009 Form 10-K		NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K, as amended by a Form 10-K/A, for the year ended December 31, 2009
AFUDC-debt		Allowance for Borrowed Funds Used During Construction
AFUDC-equity		Allowance for Equity Funds Used During Construction
ASD		Advanced Service Delivery
BCP		Bureau of Consumer Protection
BOD		Board of Directors
BTGR		Base Tariff General Rate
CalPeco		California Pacific Electric Company
Calpine		Calpine Corporation
Clark Generating Station		550 megawatt nominally rated William Clark Generating Station
CPUC		California Public Utilities Commission
CWIP		Construction Work-In-Progress
d/b/a		Doing business as
DBRS		Dominion Bond Rating Service
DEAA		Deferred Energy Accounting Adjustment
DOE		Department of Energy
DSM		Demand Side Management
Dth		Decatherm
EPA		Environmental Protection Agency
EPS		Earnings Per Share
FASB		Financial Accounting Standards Board
FASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd.
GAAP		Generally Accepted Accounting Principles in the United States
GRC		General Rate Case
Harry Allen Generating Station		142 megawatt nominally rated Harry Allen Generating Station
Higgins Generating Station		598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
kV		Kilovolt
MMBtu		Million British Thermal Units
Mohave Generating Station		1,580 megawatt nominally rated Mohave Generating Station
Moody’s		Moody’s Investors Services, Inc.
MW		Megawatt
MWh		Megawatt hour
Navajo Generating Station		255 megawatt nominally rated Navajo Generating Station
NEICO		Nevada Electrical Investment Company
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NPC		Nevada Power Company d/b/a NV Energy
NPC Credit Agreement		$600 million Revolving Credit Facility entered into in April 2010 between NPC and Wells Fargo, N.A., as administrative agent for the lenders a party thereto
NPC’s Indenture		NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank of New York Mellon Trust Company N.A., as Trustee
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
Reid Gardner Generating Station		325 megawatt nominally rated Reid Gardner Generating Station
ROR		Rate of Return
S&P		Standard & Poor’s
Salt River		Salt River Project
SEC		United States Securities and Exchange Commission
Silverhawk Generating Station		395 megawatt nominally rated Silverhawk Generating Station
SPPC		Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement		$250 million Revolving Credit Facility entered into in April 2010 between SPPC and Bank of America, N.A., as administrative agent for the lenders a party thereto
SPPC’s Indenture		SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and the Bank of New York Mellon Trust Company N.A., as Trustee
TMWA		Truckee Meadows Water Authority
Tracy Generating Station		541 megawatt nominally rated Frank A. Tracy Generating Station
U.S.		United States of America
Utilities		Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station		261 megawatt nominally rated Valmy Generating Station
WSPP		Western Systems Power Pool

Table of Contents

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


	Three Months Ended
	March 31,
	2010			2009

OPERATING REVENUES	$	716,969		$	755,267

OPERATING EXPENSES:
Fuel for power generation		221,619			230,104
Purchased power		107,363			125,387
Gas purchased for resale		65,559			70,272
Deferred energy		17,566			45,635
Other operating expenses		109,106			114,677
Maintenance		25,729			34,400
Depreciation and amortization		80,948			78,048
Taxes other than income		16,173			14,647
Total Operating Expenses		644,063			713,170
OPERATING INCOME		72,906			42,097

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: 2010-$4,939, 2009-$5,146)		(80,064	)		(82,633	)
Interest income (expense) on regulatory items		(2,071	)		1,180
AFUDC-equity		5,953			6,218
Other income		5,877			5,058
Other expense		(3,066	)		(5,578	)
Total Other Income (Expense)		(73,371	)		(75,755	)
Loss Before Income Tax Expense		(465	)		(33,658	)

Income tax expense (benefit)		1,256			(11,414	)

NET LOSS	$	(1,721	)	$	(22,244	)

Amount per share basic and diluted - (Note 9)
Net loss per share basic and diluted	$	(0.01	)	$	(0.09	)

Weighted Average Shares of Common Stock Outstanding - basic and diluted		234,858,642			234,331,044
Dividends Declared Per Share of Common Stock	$	0.11		$	0.10

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

Table of Contents

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,		December 31,
	2010		2009
ASSETS

Current Assets:
Cash and cash equivalents	$	75,928	$	62,706
Accounts receivable less allowance for uncollectible accounts: 2010 - $30,755; 2009 - $32,341		338,111		400,911
Materials, supplies and fuel, at average cost		121,321		124,040
Risk management assets (Note 6)		10,687		27,558
Deferred income taxes		131,382		87,562
Other current assets		60,410		44,298
Total Current Assets		737,839		747,075

Utility Property:
Plant in service		10,900,591		10,833,622
Construction work-in-progress		807,177		716,128
Total		11,707,768		11,549,750
Less accumulated provision for depreciation		2,943,702		2,884,199
Total Utility Property, Net		8,764,066		8,665,551

Investments and other property, net		52,279		51,169

Deferred Charges and Other Assets:
Deferred energy (Note 3)		129,323		138,963
Regulatory assets		1,272,333		1,218,778
Regulatory asset for pension plans		261,100		264,892
Risk management assets (Note 6)		4,350		6,732
Other deferred charges and assets		173,096		173,145
Total Deferred Charges and Other Assets		1,840,202		1,802,510

Assets Held for Sale (Note 10)		149,139		147,158

TOTAL ASSETS	$	11,543,525	$	11,413,463



(Continued)

Table of Contents

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,			December 31,
	2010			2009
LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities:
Current maturities of long-term debt	$	7,785		$	134,474
Accounts payable		305,165			352,000
Accrued expenses		112,540			134,328
Risk management liabilities (Note 6)		106,071			66,871
Deferred energy (Note 3)		208,378			191,405
Other current liabilities		69,929			67,301
Total Current Liabilities		809,868			946,379

Long-term debt		5,546,626			5,303,357

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		1,118,180			1,072,780
Deferred investment tax credit		21,822			22,541
Accrued retirement benefits		145,158			149,925
Risk management liabilities		4,020			2,233
Regulatory liabilities		392,054			386,019
Other deferred credits and liabilities		281,701			280,560
Total Deferred Credits and Other Liabilities		1,962,935			1,914,058

Liabilities Held for Sale (Note 10)		26,571			25,747

Shareholders' Equity:
Common stock		234,933			234,834
Other paid-in capital		2,701,355			2,700,329
Retained earnings		267,694			295,247
Accumulated other comprehensive loss		(6,457	)		(6,488	)
Total Shareholders' Equity		3,197,525			3,223,922

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	11,543,525		$	11,413,463


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



(Concluded)

Table of Contents

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

	For the Three Months Ended
	March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(1,721	)	$	(22,244	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		80,948			78,048
Deferred taxes and deferred investment tax credit		1,284			5,264
AFUDC-equity		(5,953	)		(6,218	)
Deferred energy		26,824			45,803
Other, net		21,206			16,836
Changes in certain assets and liabilities:
Accounts receivable		62,921			23,909
Materials, supplies and fuel		2,599			1,080
Other current assets		(16,113	)		(2,899	)
Accounts payable		(16,406	)		(41,216	)
Accrued retirement benefits		(4,767	)		(12,205	)
Other current liabilities		(19,100	)		(24,400	)
Risk management assets and liabilities		2,633			267
Other deferred assets		(921	)		(3,988	)
Other regulatory assets		(9,462	)		(11,251	)
Other deferred liabilities		(4,058	)		4,493
Net Cash from Operating Activities		119,914			51,279

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(200,046	)		(197,498	)
Proceeds from sale of asset		3,254			-
Customer advances for construction		(794	)		(3,260	)
Contributions in aid of construction		15,707			17,104
Investments and other property - net		(1,093	)		9
Net Cash used by Investing Activities		(182,972	)		(183,645	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		144,999			909,020
Retirement of long-term debt		(44,011	)		(695,100	)
Sale of Common Stock		1,124			818
Dividends paid		(25,832	)		(23,450	)
Net Cash from Financing Activities		76,280			191,288

Net Increase in Cash and Cash Equivalents		13,222			58,922
Beginning Balance in Cash and Cash Equivalents		62,706			54,359
Ending Balance in Cash and Cash Equivalents	$	75,928		$	113,281

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	99,559		$	92,750
Significant non-cash transactions:
Accrued construction expenses as of March 31,	$	97,357		$	146,036
Capital lease obligations incurred	$	15,336		$	-

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

Table of Contents

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


	Three Months Ended
	March 31,
	2010			2009

OPERATING REVENUES	$	426,960		$	436,529

OPERATING EXPENSES:
Fuel for power generation		156,115			154,062
Purchased power		71,227			88,206
Deferred energy		19,463			38,190
Other operating expenses		67,880			70,193
Maintenance		17,019			27,534
Depreciation and amortization		55,101			52,363
Taxes other than income		10,026			9,063
Total Operating Expenses		396,831			439,611
OPERATING INCOME (LOSS)		30,129			(3,082	)

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: 2010-$4,532, 2009-$4,562)		(53,356	)		(55,043	)
Interest income (expense) on regulatory items		(31	)		1,853
AFUDC-equity		5,362			5,621
Other income		2,583			2,342
Other expense		(1,132	)		(3,207	)
Total Other Income (Expense)		(46,574	)		(48,434	)
Loss Before Income Tax Expense		(16,445	)		(51,516	)

Income tax benefit		(4,119	)		(16,365	)

NET LOSS	$	(12,326	)	$	(35,151	)


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

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,		December 31,
	2010		2009
ASSETS

Current Assets:
Cash and cash equivalents	$	34,848	$	42,609
Accounts receivable less allowance for uncollectible accounts: 2010 - $27,318; 2009 - $29,375		216,980		254,027
Materials, supplies and fuel, at average cost		67,769		69,176
Risk management assets (Note 6)		8,542		21,902
Intercompany income taxes receivable		10,356		10,356
Deferred income taxes		101,558		58,425
Other current assets		39,128		27,855
Total Current Assets		479,181		484,350

Utility Property:
Plant in service		7,467,548		7,414,432
Construction work-in-progress		707,461		627,026
Total		8,175,009		8,041,458
Less accumulated provision for depreciation		1,768,311		1,727,710
Total Utility Property, Net		6,406,698		6,313,748

Investments and other property, net		42,199		41,167

Deferred Charges and Other Assets:
Deferred energy (Note 3)		129,323		138,963
Regulatory assets		910,400		856,769
Regulatory asset for pension plans		127,868		129,709
Risk management assets (Note 6)		4,314		5,590
Other deferred charges and assets		125,186		126,075
Total Deferred Charges and Other Assets		1,297,091		1,257,106

TOTAL ASSETS	$	8,225,169	$	8,096,371


(Continued)

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,			December 31,
	2010			2009
LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities:
Current maturities of long-term debt	$	7,785		$	119,474
Accounts payable		208,680			249,962
Accounts payable, affiliated companies		20,150			32,414
Accrued expenses		74,048			86,983
Risk management liabilities (Note 6)		79,155			39,122
Deferred energy (Note 3)		89,183			74,129
Other current liabilities		54,988			52,306
Total Current Liabilities		533,989			654,390

Long-term debt		3,779,120			3,535,440

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		835,274			794,890
Deferred investment tax credit		8,413			8,698
Accrued retirement benefits		35,213			39,678
Risk management liabilities (Note 6)		3,171			1,165
Regulatory liabilities		214,753			210,287
Other deferred credits and liabilities		204,507			201,784
Total Deferred Credits and Other Liabilities		1,301,331			1,256,502

Shareholder's Equity:
Common stock		1			1
Other paid-in capital		2,254,189			2,254,189
Retained earnings		360,019			399,345
Accumulated other comprehensive loss		(3,480	)		(3,496	)
Total Shareholder's Equity		2,610,729			2,650,039

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	8,225,169		$	8,096,371


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


(Concluded)

Table of Contents

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

	For the Three Months
	Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(12,326	)	$	(35,151	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		55,101			52,363
Deferred taxes and deferred investment tax credit		(3,990	)		19,424
AFUDC-equity		(5,362	)		(5,621	)
Deferred energy		24,695			35,928
Other, net		14,267			10,269
Changes in certain assets and liabilities:
Accounts receivable		37,047			(23,090	)
Materials, supplies and fuel		1,506			(982	)
Other current assets		(11,273	)		(4,948	)
Accounts payable		(28,951	)		(17,299	)
Accrued retirement benefits		(4,465	)		(16,580	)
Other current liabilities		(10,254	)		(9,056	)
Risk management assets and liabilities		1,577			(532	)
Other deferred assets		(531	)		(3,445	)
Other regulatory assets		(5,219	)		(10,572	)
Other deferred liabilities		(2,708	)		4,118
Net Cash from (used by) Operating Activities		49,114			(5,174	)

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(163,340	)		(141,059	)
Proceeds from sale of asset		3,254			-
Customer advances for construction		(17	)		(2,101	)
Contributions in aid of construction		14,608			15,603
Investments and other property - net		(1,014	)		(4	)
Net Cash used by Investing Activities		(146,509	)		(127,561	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		120,000			748,404
Retirement of long-term debt		(3,366	)		(540,692	)
Dividends paid		(27,000	)		(22,000	)
Net Cash from Financing Activities		89,634			185,712

Net Increase (Decrease) in Cash and Cash Equivalents		(7,761	)		52,977
Beginning Balance in Cash and Cash Equivalents		42,609			28,594
Ending Balance in Cash and Cash Equivalents	$	34,848		$	81,571

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	67,305		$	55,611
Significant non-cash transactions:
Accrued construction expenses as of March 31,	$	92,631		$	131,511
Capital lease obligations incurred	$	15,336		$	-

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

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2010			2009
OPERATING REVENUES:
Electric	$	209,981		$	237,738
Gas		80,020			80,993
Total Operating Revenues		290,001			318,731

OPERATING EXPENSES:
Fuel for power generation		65,504			76,042
Purchased power		36,136			37,181
Gas purchased for resale		65,559			70,272
Deferred energy - electric - net		(1,500	)		11,796
Deferred energy - gas - net		(397	)		(4,351	)
Other operating expenses		40,672			44,015
Maintenance		8,710			6,866
Depreciation and amortization		25,847			25,685
Taxes other than income		6,066			5,524
Total Operating Expenses		246,597			273,030
OPERATING INCOME		43,404			45,701

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: 2010-$407, 2009-$584)		(17,045	)		(17,927	)
Interest income (expense) on regulatory items		(2,040	)		(673	)
AFUDC-equity		591			597
Other income		1,755			2,715
Other expense		(1,869	)		(1,991	)
Total Other Income (Expense)		(18,608	)		(17,279	)
Income Before Income Tax Expense		24,796			28,422

Income tax expense		7,676			9,286

NET INCOME	$	17,120		$	19,136

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

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


		March 31,		December 31,
		2010		2009
ASSETS

Current Assets:
Cash and cash equivalents		$	28,530	$	14,359
Accounts receivable less allowance for uncollectible accounts:
	2010-$3,437; 2009 - $2,966		121,130		146,883
Materials, supplies and fuel, at average cost			53,500		54,802
Risk management assets (Note 6)			2,145		5,656
Intercompany income taxes receivable			19,315		19,315
Deferred income taxes			63,159		46,414
Other current assets			21,144		16,056
Total Current Assets			308,923		303,485

Utility Property:
Plant in service			3,433,043		3,419,190
Construction work-in-progress			99,716		89,102
Total			3,532,759		3,508,292
Less accumulated provision for depreciation			1,175,391		1,156,489
Total Utility Property, Net			2,357,368		2,351,803

Investments and other property, net			5,596		5,428

Deferred Charges and Other Assets:
Regulatory assets			361,932		362,009
Regulatory asset for pension plans			128,389		130,283
Risk management assets (Note 6)			36		1,142
Other deferred charges and assets			42,056		40,837
Total Deferred Charges and Other Assets			532,413		534,271

Assets Held for Sale (Note 10)			149,139		147,158

TOTAL ASSETS		$	3,353,439	$	3,342,145


(Continued)

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


	March 31,			December 31,
	2010			2009
LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities:
Current maturities of long-term debt	$	-		$	15,000
Accounts payable		81,582			76,867
Accounts payable, affiliated companies		15,436			21,091
Accrued expenses		33,439			34,185
Risk management liabilities (Note 6)		26,916			27,749
Deferred energy (Note 3)		119,195			117,276
Other current liabilities		14,944			14,996
Total Current Liabilities		291,512			307,164

Long-term debt		1,281,863			1,282,225

Commitments and Contingencies (Note 8)

Deferred Credits and Other Liabilities:
Deferred income taxes		374,132			350,802
Deferred investment tax credit		13,409			13,843
Accrued retirement benefits		104,213			104,854
Risk management liabilities (Note 6)		849			1,068
Regulatory liabilities		177,301			175,732
Other deferred credits and liabilities		70,201			71,452
Total Deferred Credits and Other Liabilities		740,105			717,751

Liabilities Held for Sale (Note 10)		26,571			25,747

Shareholder's Equity:
Common stock		4			4
Other paid-in capital		1,111,260			1,111,260
Retained earnings		(95,480	)		(99,601	)
Accumulated other comprehensive loss		(2,396	)		(2,405	)
Total Shareholder's Equity		1,013,388			1,009,258

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	3,353,439		$	3,342,145


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


(Concluded)

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

	For the Three Months
	Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	17,120		$	19,136
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		25,847			25,685
Deferred taxes and deferred investment tax credit		7,534			8,597
AFUDC-equity		(591	)		(597	)
Deferred energy		2,129			9,875
Other, net		6,494			6,395
Changes in certain assets and liabilities:
Accounts receivable		25,874			28,901
Materials, supplies and fuel		1,084			2,085
Other current assets		(5,087	)		1,828
Accounts payable		4,894			(23,069	)
Accrued retirement benefits		(641	)		4,179
Other current liabilities		(740	)		(6,672	)
Risk management assets and liabilities		1,056			799
Other deferred assets		(390	)		(543	)
Other regulatory assets		(4,243	)		(679	)
Other deferred liabilities		(1,019	)		(75	)
Net Cash from Operating Activities		79,321			75,845

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(36,706	)		(56,439	)
Customer advances for construction		(777	)		(1,159	)
Contributions in aid of construction		1,099			1,501
Investments and other property - net		(169	)		14
Net Cash used by Investing Activities		(36,553	)		(56,083	)

CASH FLOWS USED BY FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		24,999			160,616
Retirement of long-term debt		(40,596	)		(154,359	)
Investment by parent company		-			90,300
Dividends paid		(13,000	)		(108,800	)
Net Cash used by Financing Activities		(28,597	)		(12,243	)

Net Increase (Decrease) in Cash and Cash Equivalents		14,171			7,519
Beginning Balance in Cash and Cash Equivalents		14,359			21,411
Ending Balance in Cash and Cash Equivalents	$	28,530		$	28,930

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	15,870		$	20,755
Significant non-cash transactions:
Accrued construction expenses as of March 31,	$	4,726		$	14,525

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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Pacific Energy Company, NVE Insurance Company, Inc. and Sierra Gas Holding Company. All intercompany balances and transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with 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 NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain 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 the 2009 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the three months ended March 31, 2010, are not necessarily indicative of the results to be expected for the full year.

Recent Accounting Standards Updates

Consolidations of Variable Interest Entities

In June 2009, the FASB amended existing guidance related to the Consolidation of Variable Interest Entities. NVE and the Utilities adopted this amendment on January 1, 2010. The amendment no longer allows the scope exception for contracts which an entity was unable to obtain financial information from to be excluded from the primary beneficiary determination. As a result, NVE and the Utilities will continually perform an analysis to determine whether their variable interests give it controlling financial interest in a variable interest entity which would require consolidation. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both the following characteristics: a) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. To identify potential variable interests, management reviewed contracts under leases, long term purchase power contracts, tolling contracts and jointly owned facilities. The Utilities identified contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary as defined above, as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. As of March 31, 2010, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.

Fair Value Measurements and Disclosures

In January 2010, the FASB amended the Fair Value Measurements and Disclosure Topic as reflected in the FASB Accounting Standards Codification for recurring and nonrecurring fair value measurements. NVE and the Utilities adopted this amendment on January 1, 2010. The new accounting guidance adds requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. In addition, the accounting update amends guidance on employers’ disclosures about postretirement benefit plan assets to require disclosures by classes of assets instead of by major categories of assets. The amendment is effective for NVE and the Utilities as of January 1, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in Level

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3 fair value measurements. Those disclosures will be effective for NVE and the Utilities as of January 1, 2011. The adoption of this guidance did not have, nor is expected to have, a significant impact on the disclosure requirements for NVE and the Utilities.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as required by the Segment Reporting Topic of the FASC) which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other information includes amounts 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. 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 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			NVE			NVE
March 31, 2010	Electric		Electric			Gas			Total			Other			Consolidated
Operating Revenues	$	426,960	$	209,981		$	80,020		$	290,001		$	8		$	716,969

Energy Costs:
Fuel for power generation		156,115		65,504						65,504			-			221,619
Purchased power		71,227		36,136						36,136			-			107,363
Gas purchased for resale							65,559			65,559			-			65,559
Deferred energy - net		19,463		(1,500	)		(397	)		(1,897	)		-			17,566
	$	246,805	$	100,140		$	65,162		$	165,302		$	-		$	412,107

Gross Margin	$	180,155	$	109,841		$	14,858		$	124,699		$	8		$	304,862

Other operating expense		67,880								40,672			554			109,106
Maintenance		17,019								8,710						25,729
Depreciation and amortization		55,101								25,847						80,948
Taxes other than income		10,026								6,066			81			16,173

Operating Income (Loss)	$	30,129							$	43,404		$	(627	)	$	72,906


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 - 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 operating expense		70,193								44,015		469			114,677
Maintenance		27,534								6,866					34,400
Depreciation and amortization		52,363								25,685					78,048
Taxes other than income		9,063								5,524		60			14,647

Operating Income (Loss)	$	(3,082	)						$	45,701	$	(522	)	$	42,097

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NOTE 3. REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy amounts were included in the consolidated balance sheets as of March 31, 2010 (dollars in thousands):

	March 31, 2010
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2010 DEAA	$	(98,726	)	$	(100,485	)	$	(16,996	)	$	(216,207	)
2010 Amortization		-			5,235			3,491			8,726
2010 Deferred Energy Over Collections (1)		(16,721	)		(7,069	)		(3,371	)		(27,161	)
Nevada Deferred Energy Balance at March 31, 2010 - Subtotal	$	(115,447	)	$	(102,319	)	$	(16,876	)	$	(234,642	)
Cumulative CPUC balance		-			632			-			632
Western Energy Crisis Rate Case (effective 6/07, 3 years)		11,204			-			-			11,204
Reinstatement of deferred energy (effective 6/07, 10 years)		144,383			-			-			144,383

Total	$	40,140		$	(101,687	)	$	(16,876	)	$	(78,423	)

Current Assets
Other deferred charges (2)		-			632			-			632
Deferred Assets
Deferred energy		129,323			-			-			129,323
Current Liabilities
Deferred energy		(89,183	)		(102,319	)		(16,876	)		(208,378	)
Total	$	40,140		$	(101,687	)	$	(16,876	)	$	(78,423	)

(1)	These deferred energy over collections are to be requested in March 2011 DEAA filings, and include PUCN ordered adjustments.
(2)	Refer to Note 10, Assets Held For Sale.

Pending Regulatory Actions

Nevada Power Company

NPC DEAA

In March 2010, NPC filed an application to create a new DEAA rate. In its application, NPC requests to decrease rates by $96.4 million, a decrease of 4.18%, while refunding $98.7 million of deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2010. Hearings are scheduled for August 2010.

Separately, NPC filed a petition to offset the NPC DEAA over collection (credit balance) of $98.7 million against the deferred BTGR debit balance of $95.8 million. Reference NPC’s 2008 GRC in Note 3, Regulatory Actions, of the Notes to Financial Statements of the 2009 Form 10-K for additional information. This proposal would eliminate the deferred BTGR balance for non-residential customers while decreasing the residential customer deferred BTGR balance to $36.6 million. If accepted, the petition would result in a decrease of $37.3 million or 1.6% in total revenues for NPC. This docket has been combined with the DEAA docket and hearings are scheduled for August 2010.

Sierra Pacific Power Company

SPPC California Divestiture Filing

In October 2009, SPPC and CalPeco filed an application with the CPUC requesting approval of the transaction in which SPPC has agreed to sell its California electric distribution and generation assets to CalPeco. Upon closing of the transaction, SPPC will transfer to CalPeco all of its California electric distribution and generation assets and approximately 46,000 retail electric customers. Separately in December 2009, SPPC filed an application with the PUCN requesting PUCN approval of the transaction. On or before July 1, 2010, SPPC will file certain components of the transaction under its IRP process and request consolidation with the previously filed application. See Note 10, Assets Held for Sale.

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SPPC Nevada Gas DEAA

In March 2010, SPPC filed an application to create a new DEAA rate. In its application, SPPC requests to decrease rates by $8.3 million, a decrease of 4.66%, while refunding approximately $17 million of deferred gas costs. The new DEAA rate will be effective October 1, 2010. Hearings are scheduled for August 2010.

SPPC Nevada Electric DEAA

In March 2010, SPPC filed an application to create a new DEAA rate. In its application, SPPC requests to decrease rates by $75.9 million, a decrease of 9.73%, while refunding $100.5 million of deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2010. Hearings are scheduled for August 2010.

NOTE 4. LONG-TERM DEBT

As of March 31, 2010, NPC’s, SPPC’s and 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		NVE Holding Co. and Other Subs.		NVE Consolidated
2010	$	3,069		$	-	$	-	$	3,069
2011		368,454			-		-		368,454
2012		134,822			100,000		63,670		298,492
2013		235,405			250,000		-		485,405
2014		128,513			-		230,039		358,552
		870,263			350,000		293,709		1,513,972
Thereafter		2,928,355			916,417		191,500		4,036,272
		3,798,618			1,266,417		485,209		5,550,244
Unamortized Premium (Discount) Amount		(11,713	)		15,446		434		4,167
Total	$	3,786,905		$	1,281,863	$	485,643	$	5,554,411

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

NPC

$600 Million Revolving Credit Facility

In April 2010, NPC terminated its $589 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $600 million secured revolving credit facility, maturing in April 2013. Accordingly, the $230 million balance outstanding on the $589 million revolving credit facility as of March 31, 2010, has been classified as long-term debt. The fees on the $600 million revolving credit facility for the unused portion and on the amounts borrowed have increased reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, N.A. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $600 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the availability under the revolving credit facility to NPC shall not be less than 50% of the total commitments thereunder.

The NPC Credit Agreement contains one financial maintenance covenant that 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. In the event that NPC did not meet the financial maintenance covenant or there is an event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition

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would be a condition to borrowing under the revolving credit facility. The calculation of NPC’s negative mark-to-market exposure as of April 30, 2010 was approximately $79.3 million.

SPPC

$250 Million Revolving Credit Facility

In April 2010, SPPC terminated its $332 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $250 million secured revolving credit facility, maturing in April 2013. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have increased reflecting current market conditions. The Administrative Agent for the facility is Bank of America, N.A. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the availability under the revolving credit facility to SPPC shall not be less than 50% of the total commitments thereunder.

The SPPC Credit Agreement contains one financial maintenance covenant that 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. In the event that SPPC did not meet the financial maintenance covenant or there is an event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility. The calculation of SPPC’s negative mark-to-market exposure as of April 30, 2010 was approximately $25.2 million.

NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The March 31, 2010 carrying amount of cash and cash equivalents, current assets and current liabilities approximate fair value due to the short-term nature of these instruments.

The total fair value of NVE’s consolidated long-term debt at March 31, 2010, is estimated to be $5.8 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $5.6 billion as of December 31, 2009.

The total fair value of NPC’s consolidated long-term debt at March 31, 2010, is estimated to be $4.0 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $3.7 billion at December 31, 2009.

The total fair value of SPPC’s consolidated long-term debt at March 31, 2010, is estimated to be $1.4 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.3 billion as of December 31, 2009.

NOTE 6. DERIVATIVES AND HEDGING ACTIVITIES

NVE, NPC and SPPC apply the accounting guidance as required by the Derivatives and Hedging Topic of the FASC. The accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities, 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. The accounting guidance for derivative instruments also provides a scope exception for commodity 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

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normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value.

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. 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’ to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities to reduce the risks associated with volatile electricity and natural gas markets.

Interest Rate Risk

In August 2009, NPC entered into two interest rate swap agreements which terminate in 2011, for an aggregated notional amount of $350 million associated with its $350 million 8.25% General and Refunding Mortgage Notes, Series A, due 2011. The interest rate swaps manage the existing fixed rate interest rate exposure with a variable interest rate in order to lower overall borrowing costs. As allowed by the Regulated Operations Topic of the FASC, as of March 31, 2010, the fair value of the interest rate swaps were recorded as a Risk Management Asset with the corresponding offset recorded as a Risk Management Regulatory Liability and are included in the fair value table below.

Credit Risk Contingent Features

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, S&P and Fitch Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities’ Senior Unsecured or equivalent 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, 2010, the maximum amount of collateral NPC and SPPC would have been required to post under these agreements is approximately $76.8 million and $27.8 million, respectively, based on mark-to-market liability values, which are substantially based on quoted market prices. Of this amount, approximately $54.7 million and $22.7 million, respectively, would have been required if NPC and SPPC are downgraded one level and additional amounts of approximately $22.1 million and $5.1 million would be required, respectively, if NPC and SPPC are downgraded two levels. However, as discussed in Note 4, Long-Term Debt, as a result of the Utilities’ entering into new revolving credit facilities, the Utilities are no longer required to post collateral for these counterparties, but their availability on their revolving credit facilities will be reduced by any negative mark-to-market positions with these counterparties, provided that any such reduction will not exceed 50% of the total commitments thereunder.

Determination of Fair Value

As required by the Fair Value Measurements and Disclosure Topic of the FASC, 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, options and interest rate swaps. Total risk management assets below do not include option premiums on commodity contracts 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 for NVE, NPC and SPPC were as follows (dollars in millions):

	March 31, 2010						December 31, 2009
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	10.6	$	8.5	$	2.1	$	11.9	$	9.2	$	2.7
Non-Current		0.5		0.5		0.0		1.9		1.4		0.5
Total	$	11.1	$	9.0	$	2.1	$	13.8	$	10.6	$	3.2

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 using an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option

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volatility rates. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative instruments not only includes counterparty risk, but also the impact of NVE and the Utilities nonperformance risk on their liabilities, which as of March 31, 2010, had an immaterial impact to the fair value of their derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the consolidated balance sheets of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria as required by the Derivatives and Hedging Topic of the FASC. Due to regulatory accounting treatment under which the utilities operate, regulatory assets and liabilities are established to the extent that 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 derivative transactions until the period of settlement (dollars in millions):

	March 31, 2010									December 31, 2009
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current	$	0.1		$	0.1		$	0.0		$	15.7		$	12.7		$	3.0
Risk management assets- noncurrent(1)		3.8			3.8			0.0			4.8			4.2			0.6
Total risk management assets		3.9			3.9			0.0			20.5			16.9			3.6

Risk management liabilities- current		106.1			79.2			26.9			66.9			39.1			27.8
Risk management liabilities- noncurrent		4.0			3.2			0.8			2.2			1.1			1.1
Total risk management liabilities		110.1			82.4			27.7			69.1			40.2			28.9

Risk management regulatory assets/liabilities – net (2)	$	(106.2	)	$	(78.5	)	$	(27.7	)	$	(48.6	)	$	(23.3	)	$	(25.3	)

(1)

Included in Risk management assets – noncurrent at March 31, 2010, is a $3.8 million cumulative gain for interest rate swaps with the offset recorded in the risk management regulatory assets/liabilities amounts above.

(2)

When amount is negative it represents a risk management regulatory asset, when positive it represents a risk management regulatory liability. For the three months ended March 31, 2010, NVE, NPC and SPPC would have recorded a loss of $57.6 million, $55.2 million, and $2.4 million, respectively; however, as permitted by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains and losses, which are included in the risk management regulatory assets/liabilities amounts 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’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in market prices. The increase in risk management liabilities as of March 31, 2010, as compared to December 31, 2009, is primarily due to a decrease in natural gas prices relative to contract prices compared to natural gas prices at December 31, 2009.

The following table shows the commodity volume for our open derivative contracts related to natural gas contracts (amounts in millions):

	March 31, 2010						December 31, 2009
	Commodity Volume (MMBTU)						Commodity Volume (MMBTU)
	NVE		NPC		SPPC		NVE		NPC		SPPC

Commodity volume assets- current		0.4		0.3		0.1		47.1		40.7		6.4
Commodity volume assets- noncurrent		0.0		0.0		0.0		10.3		7.6		2.7
Total commodity volume of assets		0.4		0.3		0.1		57.4		48.3		9.1

Commodity volume liabilities- current		84.4		64.6		19.8		51.7		32.7		19.0
Commodity volume liabilities- noncurrent		5.6		4.7		0.9		7.8		5.3		2.5
Total commodity volume of liabilities		90.0		69.3		20.7		59.5		38.0		21.5

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NOTE 7. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other post-retirement costs for the three months ended March 31 follows. This summary is based on a December 31, measurement date (dollars in thousands):

NVE, Consolidated	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009

Service cost	$	4,727		$	4,709		$	617		$	577
Interest cost		10,718			11,036			2,184			2,637
Expected return on plan assets		(11,069	)		(9,290	)		(1,556	)		(1,508	)
Amortization of prior service cost		(448	)		(448	)		(972	)		(171	)
Amortization of net loss		3,777			6,894			1,085			1,273
Settlement loss		-			-			-			84

Net periodic benefit cost	$	7,705		$	12,901		$	1,358		$	2,892

The average percentage of NVE net periodic costs capitalized during 2010 and 2009 were 33.20% and 36.24% respectively.

NPC	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009

Service cost	$	2,392		$	2,393		$	353		$	310
Interest cost		5,023			5,270			619			607
Expected return on plan assets		(5,362	)		(4,462	)		(567	)		(509	)
Amortization of prior service cost		(433	)		(433	)		236			289
Amortization of net loss		1,764			3,298			300			287
Settlement loss		-			-			-			19

Net periodic benefit cost	$	3,384		$	6,066		$	941		$	1,003

The average percentage of NPC net periodic costs capitalized during 2010 and 2009 were 35.93% and 40.23% respectively.

SPPC	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009

Service cost	$	2,004		$	2,061		$	245		$	251
Interest cost		5,389			5,471			1,547			2,014
Expected return on plan assets		(5,431	)		(4,580	)		(961	)		(977	)
Amortization of prior service cost		(26	)		(26	)		(1,213	)		(465	)
Amortization of net loss		1,969			3,425			777			978
Settlement loss		-			-			-			65

Net periodic benefit cost	$	3,905		$	6,351		$	395		$	1,866

The average percentage of SPPC net periodic costs capitalized during 2010 and 2009 were 33.70% and 35.03% respectively.

In the quarter ended March 31, 2010, the company made a contribution to the pension plan in the amount of $10 million, allocated to the 2010 plan year. Additional funding may be required for both the pension and other post-retirement benefits plans in 2010 in order to meet the minimum funding requirements under the Pension Protection Act of 2006; however, the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution. Currently, NVE expects to fund approximately $40 million to the pension plan in 2010.

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NOTE 8. COMMITMENTS AND CONTINGENCIES

Environmental

NPC

NEICO

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

SPPC

Valmy Generating Station

On June 22, 2009, SPPC received a request for information from the EPA—Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada. SPPC co-owns and operates this coal-fired plant. Idaho Power Company owns the remaining 50%. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the EPA relating to the plant. SPPC completed its response to the EPA in December 2009 and will continue to monitor developments relating to this Section 114 request. SPPC cannot predict the impact, if any, associated with this information request.

Other 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 Notes to Financial Statements, Environmental, in the 2009 Form 10-K, NPC was subject to various environmental proceedings which were settled as of December 31, 2009. NPC continues to comply with these environmental commitments. As of March 31, 2010, environmental expenditures did not change materially from those disclosed in the 2009 Form 10-K.

Litigation Contingencies

NPC and SPPC

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station which is located in Northern Arizona and is operated by Salt 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 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 in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

The Navajo Joint owners were first served in the Missouri lawsuit in January 2005. The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners. In July 2008, the Court dismissed 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

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outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. Initially, the DC Lawsuit sought $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease In July 2001, the U.S. District Court dismissed all claims against Salt River. The action had been stayed since October, 2004 until March, 2008, when the U.S. District Court lifted the stay. On April 12, 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages. The Court ordered substantial completion of factual discovery (except for certain depositions) by July 15, 2010. Management cannot predict the timing or outcome of a decision on this matter.

SPPC

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to 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 not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in 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 determined SPPC would be entitled to actual cash value of approximately $1.3 million. SPPC has requested the court to reconsider the cash value to reflect rebuild costs. On July 10, 2009, the District Court declined SPPC’s request to reconsider the cash value and further ordered that the three year period to replace the dam commences as of July 10, 2009 (Order). In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the U.S. Court of Appeals for the Ninth Circuit. Subsequently, in August 2009, the Insurers appealed the District Court’s insurance coverage decision with the Ninth Circuit. All briefings have been completed. It is expected that the Ninth Circuit will order arguments on the appeal either late in 2010 or early to mid 2011.

Other Legal Matters

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

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NOTE 9. EARNINGS PER SHARE (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, 2010 and 2009, these items are anti-dilutive and diluted EPS for the period is computed using the weighted average number of shares outstanding before dilution.

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

		Three Months Ended March 31,
		2010			2009
Basic and Diluted EPS
Numerator ($000)

	Net loss	$	(1,721	)	$	(22,244	)

Denominator (1)
	Weighted average number of common shares outstanding		234,858,642			234,331,044

Per Share Amounts

	Net loss per share - basic and diluted	$	(0.01	)	$	(0.09	)

(1)

The denominator does not include stock equivalents for stock options, restricted and performance shares issued under the executive long-term incentive plan, shares issuable under the non-employee director stock plan and the employee stock purchase plan shares for the periods ending March 31, 2010 and 2009, due to their anti-dilutive effect in the calculation of diluted EPS. The amounts that would otherwise be included in the calculation for the periods ending March 31, 2010 and 2009 are 585,241 and 284,221 shares, respectively. The denominator also does not include stock equivalents for all the options issued under the non-qualified stock option plan for the years ended March 31, 2010 and 2009, due to conversion prices being higher than market prices for all periods. Under this plan, an additional 714,628 and 1,072,678 shares, respectively, would be included in each of these periods if the conditions for conversion were met.

NOTE 10. ASSETS HELD FOR SALE

In April 2009, SPPC entered into an agreement to sell its California electric distribution and generation assets to CalPeco. 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 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.

Below are the major classes of assets and liabilities held for sale and presented in the consolidated balance sheets as of March 31, 2010 and December 31, 2009 (dollars in millions):

Assets	March 31, 2010		December 31, 2009
Utility Plant in Service	$	190.1	$	188.6
Less: Accumulated depreciation		54.2		55.4
Utility Plant in Service, net		135.9		133.2
CWIP		3.9		4.6
Other current assets		8.7		8.6
Deferred Charges		0.6		0.8

Assets Held for Sale	$	149.1	$	147.2

Liabilities
Deferred Credits and Other Liabilities	$	26.6	$	25.7
Liabilities Held for Sale	$	26.6	$	25.7

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NOTE 11. SUBSEQUENT EVENTS

On May 4, 2010, NVE’s BOD declared a quarterly cash dividend of $0.11 cents per share payable on June 16, 2010 to common shareholders of record on June 1, 2010.

On May 4, 2010, NPC and SPPC declared a dividend to NVE of $26 million and $12 million, respectively.

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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 NVE, NPC or 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, a decrease in tourism, particularly in southern Nevada, and cancelled or deferred hotel construction projects, each of which affect customer growth, 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, increased unemployment, and energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)	changes in environmental laws or regulations, including the imposition of limits on emissions of carbon dioxide or other greenhouse gases from electric generating facilities, which could significantly affect our existing operations as well as our construction program;

(4)

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;

(5)

employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, the ability to adjust the labor cost structure to changes in growth within our service territories, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce;

(6)

the ability and terms upon which 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, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

(7)	whether the Utilities can procure and/or obtain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada;

(8)

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

(9)

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), suspension of a hedging program, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs) and/or power, or a ratings downgrade;

(10)

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;

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(11)

whether the Nevada Supreme Court's January 28, 2010 ruling in Great Basin Water Network v. Nevada State Engineer could impact some of NVE's pending water appropriation applications and could impact the pending water appropriation applications of other third parties, which, respectively, could have an adverse effect on the Utilities' water rights and/or the water supply necessary for the operation of the Utilities' generating units, and, with respect to the pending water appropriation applications of third parties, may affect the water supply to the Utilities' service territories, which could have an adverse impact on future growth and customer usage patterns;

(12)	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;

(13)	whether the Utilities will be able to integrate the new advanced metering system with their billing and other computer information systems and whether the technologies and equipment will perform as expected, and in all other respects, meet operational, commercial and regulatory requirements;

(14)

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;

(15)

the discretion of NVE's BOD regarding NVE's future common stock dividends based on the BOD 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;

(16)	further increases in the unfunded liability or 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;

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

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

(19)	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;

(20)

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; and

(21)	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. 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

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•	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.

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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 NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes the following:

●	For each of NVE, NPC and SPPC:

	§	Results of Operations
	§	Analysis of Cash Flows
	§	Liquidity and Capital Resources

●	Regulatory Proceedings (Utilities)

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 and distribution of natural gas. Other operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues. NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

NVE incurred a net loss of $1.7 million for the three months ended March 31, 2010 compared to a net loss of $22.2 million for the same period in 2009. The increase in consolidated gross margin and the reduction in net loss of approximately $21 million is primarily due to increased rates as a result of NPC’s GRC, which was effective beginning July 1, 2009.

The Utilities are regulated by the PUCN and, for the California electric service territory of SPPC, the CPUC, with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

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 due to varying weather, customer growth and other energy usage patterns 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 timely recovery of purchased power and fuel costs, and other costs, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2010 and Beyond Objectives and Challenges

In 2010, management’s key objectives will remain focused on implementing our three part strategy of energy efficiency and conservation programs for our customers, purchase and development of renewable energy projects and construction of generating facilities and expansion of transmission capability. Another key objective will be to obtain PUCN approval of NPC’s IRP and to file SPPC’s IRP. The approval of NPC’s IRP will enable us to fulfill our three part strategy by increasing the dollars spent on DSM projects, implementing our ASD initiative, approval of the ON Line transmission line, which will connect the northern and southern service area and also provide greater access to renewable energy resources. However, due to the economic uncertainty in Nevada, NVE’s execution of the three part strategy will be a significant challenge. Another challenge will be to further broaden our access to capital to fund the three-part strategy and maintain sufficient liquidity.

Economic Conditions

Although the economy in the U.S. is starting to show signs of recovery from the recession, Nevada continues to struggle. As of March 2010, the unemployment rate in Nevada was 13.4%, up 2.8% from a year ago. As of January 2010, taxable sales have declined 8.1% and gaming revenues decreased 3.2%, while visitor volume increased slightly by 1.6% compared to a year ago January 2009.

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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. As of March 2010, unemployment in the Las Vegas area was 13.8%, up 3.2% from a year ago. In addition to employment, management continues to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas as signs of future growth in customers and customer usage. As of February 2010, the hotel/motel occupancy rate in Las Vegas has decreased approximately 5.0% from a year ago. In 2010, room growth is expected to increase by 2.7% and then slow to 0.1% in 2011. The increase in room growth for 2010 is primarily due to The Cosmopolitan Resort & Casino, which is expected to add approximately 3,000 rooms to Las Vegas. Gaming properties in southern Nevada are experiencing financial problems, including difficulties meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases. In southern Nevada, construction activity, another leading indicator, has seen a decrease in the number of commercial permits while residential permits have remained relatively flat.

SPPC’s service territory, which consists primarily of Washoe County, has also been affected by the recessionary environment. Unemployment in Washoe County was at 13.2% as of March 2010, up 2.0% from a year ago. Taxable sales decreased 4.8%, and gaming revenues decreased 8.7% as of January 2010 compared to the same period in 2009. 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 continue to endure economically, management will continue to place a significant emphasis on evaluating the foregoing economic indicators and their effect on various interrelated factors including, but not limited to:

•	customer growth;
•	customer usage;
•	revenues;
•	load factors;
•	future capital projects and capital requirements;
•	managing operating and maintenance expenses within projected revenue growth without compromising safety, reliability and efficiency;
•	our liquidity and ability to access capital markets;
•	collections on accounts receivable;
•	counterparty risk; and
•	workforce reduction.

Management cannot predict when economic recovery may occur in Nevada, but expects that the Nevada economy will continue to struggle for the next several years. As such, a significant challenge for us will be to manage costs, while remaining steadfast in carrying out our three part strategy of the energy supply plan which includes energy efficiency and conservation programs; purchase and development of renewable energy projects and expansion of traditional generating capacity and transmission capability to move energy throughout the state. In response to this challenge, the three part strategy will become more focused on projects that will allow us to leverage existing assets, improve transmission capabilities which is necessary for the Utilities to meet their Portfolio Standard, discussed below, further develop the ASD initiative, which will allow us to reduce our cost structure and future capital expenditures and effectively contain capital and operating costs. Effective capital and operating cost containment began during 2009 by the reduction and delay of capital expenditures and implementation of severance programs as discussed further in Note 17, Severance Programs, of the Notes to Financial Statements in the 2009 Form 10-K.

Three Part Strategy

Beginning in 2007, NVE embarked on a three part energy supply strategy to manage resources against our load by encouraging energy efficiency and conservation programs, the purchase and development of renewable energy projects, construction of generating facilities, and expansion of transmission capability in an effort to reduce our reliance on purchased power.

Energy Efficiency and Conservation Programs

Over the past two years, the Utilities invested approximately $120 million in energy efficiency and conservation. The Utilities expect to invest approximately $63 million during 2010, of which $35.6 million is pending approval before the PUCN in NPC’s IRP. Hearings are scheduled to begin in May 2010. The final amount may be adjusted by numerous factors, such as the economy, the impact of federal government stimulus legislation, and the performance of existing and new programs.

In addition, NVE has been awarded a $138 million grant in stimulus funding from the DOE specifically for NVE’s $301 million ASD initiative. The ASD initiative will provide NVE with the Smart Grid infrastructure necessary to enable widespread use of smart meters, enabling customers to more directly manage their energy usage. The ASD initiative entails the deployment of a

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delivery mechanism that sets a new, more advanced foundation for NVE’s demand response and energy efficiency and conservation programs.

The agreement between NVE and the DOE was signed in March 2010. As a result of executing the contract, the Utilities have begun a pilot program with the ultimate goal of completing the installation of approximately 1.5 million smart meters throughout the entire state of Nevada by 2012, making Nevada one of the first states to implement a statewide Smart Grid Plan.

NVE has submitted a plan in NPC’s 2009 IRP filed in February 2010 with a proposed company investment of $95 million and a demand response program budget of $16 million. SPPC’s investment of $50 million is expected to be submitted in its next IRP amendment filing. An additional $2 million within NVE’s capital budget covers energy management system upgrades in 2010.

Additional key objectives include management of energy risk, environmental matters, and regulatory filings, and to further broaden access to capital.

Purchase and Development of Renewable Energy Projects

NPC’s current capital budget includes investing approximately $112.3 million for renewable energy projects through 2012. In 2008, NPC entered into contracts to either jointly construct or pursue the development of projects using wind, geothermal and recovered energy generation technologies, and in 2009 received PUCN approval to purchase the output from three geothermal plants expanded by 32 MW, an additional 49 MW of output from two new solar projects, and a landfill gas project to be completed in 2010/2011. In 2010, the Utilities will continue development of these renewable energy projects, conduct additional requests for proposals for renewable energy, and explore other opportunities to add to their supplies of renewable energy and associated PECs.

During the first quarter of 2010, NPC submitted seven long-term renewable energy PPAs to the PUCN for approval. The seven contracts include two solar projects totaling 160 MW, three geothermal projects totaling 130 MW, one wind project totaling 150 MW and one landfill gas project with a capacity of 3 MW. Together the projects total 443 MW.

In addition, two short-term renewable energy PPAs were entered into. One was signed in December 2009 with renewable energy deliveries commencing at that time and the other agreement was signed in February 2010 with deliveries commencing in April 2010.

In April 2010, NPC and SPPC filed their joint Annual Compliance Report with the PUCN. SPPC reported that it met the Portfolio Standard for total PECs and the solar requirements of the Portfolio Standard. NPC reported that it met the solar requirement of the Portfolio Standard, but did not meet the Portfolio Standard requirement for total PECs. However, NPC expects that the shortfall in 2009 will be offset with credits earned in 2010.

Construction of Generating Facilities and Expansion of Transmission Capabilities

In 2010, NPC will continue the construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011. In addition, the Utilities will continue to optimize the operations of their existing generating assets.

In NPC’s IRP filed in February 2010 and SPPC’s 8th Amendment to its 2007 IRP filed in March 2010, the Utilities are requesting approval of ON Line, a 500 kV transmission line from the proposed Robinson Summit Substation near Ely, Nevada to the existing Harry Allen Substation located northeast of Las Vegas, Nevada at an aggregate cost of approximately $509 million. The preferred plan is a joint ownership proposal (“Joint Project”) of the line among NPC, SPPC and Great Basin Transmission, LLC (“GBT”), an affiliate of LS Power. The Utilities have entered into a Memorandum of Understanding and Term Sheet (“MOU”) for the Joint Project that contemplates two phases of development. The Joint Project is subject to negotiation of definitive agreements and other conditions, such as PUCN and FERC approvals. The alternative to the Joint Project, also filed in NPC’s IRP and SPPC’s 8th Amendment to its 2007 IRP, is for the Utilities’ to self build the ON Line. In addition to connecting NVE’s northern service territory with its service territory in southern Nevada, the ON Line would also provide access to isolated renewable energy resources in parts of northern and eastern Nevada, which would further advance the Utilities’ ability in meeting its Portfolio Standard, discussed above.

Further Broaden Access to Capital

A significant focus in 2010 will again be to generate sufficient cash from operations to meet 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. Maintaining or improving the Utilities credit ratings will be essential to negotiating favorable financing terms, and will continue to be a significant focus in 2010. Depending on the approval of NPC’s IRP, significant amounts of capital may be necessary to fund prospective construction projects, as discussed further under NVE’s Liquidity and Capital Resources in the 2009 Form 10-K. Additionally, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a

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timely manner, the Utilities may need to issue additional debt to support their operating costs or delay capital expenditures. Management may be required to meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and/or the issuance of equity by NVE. As such, the ability to issue new debt or equity securities on favorable terms will be a significant focus in 2010. In April 2010, NPC and SPPC entered into new revolving credit facilities for $600 million and $250 million, respectively, which expire in April 2013 to replace their credit facilities expiring in November 2010.

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $9.4 million of long term debt interest costs for each of the three months ended March 31, 2010 and 2009, respectively.

As of March 31, 2010, NPC had paid $27 million in dividends to NVE and SPPC had paid $13 million in dividends to NVE. On May 4, 2010, NPC and SPPC declared a dividend to NVE of $26 million and $12 million, respectively.

Other Subsidiaries

Other Subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the three months ended March 31, 2010 compared to the same period in 2009 due to a decrease in cash from financing activities and an increase in cash used by investing activities, partially offset by an increase in cash from operating activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to increased revenues as a result of the rate increase in NPC’s GRC. Also contributing to the increase were higher payments to vendors and pension plan funding in the first quarter of 2009, a reduction in spending for conservation programs and other regulated activities and the timing of interest payments. These increases were partially offset by a reduction in BTER rates charged to customers and the timing of property tax payments.

Cash Used By Investing Activities. Cash used by investing activities increased mainly due to continuing construction at the Harry Allen Generating Station. This increase was partially offset by the slowdown in construction for infrastructure.

Cash From Financing Activities. Cash from financing activities decreased due to a reduction in draws on the Utilities revolving credit facilities.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

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 March 31, 2010 (in millions)
	NVE		NPC		SPPC
Cash and Cash Equivalents	$	10.6	$	34.8	$	28.5
Balance available on Revolving Credit Facilities (1)(2)		N/A		344.3		316.2

	$	10.6	$	379.1	$	344.7

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(1)	NPC’s and SPPC’s balances as of March 31, 2010 reflect amounts available under their $589 million and $332 million revolving credit facilities, respectively. In April 2010, NPC and SPPC entered into new revolving credit facilities with a capacity of $600 million and $250 million, respectively. See NPC and SPPC Financing Transactions.
(2)	As of May 4, 2010, NPC and SPPC had approximately $285.0 million and $208.5 million available under their revolving credit facilities which includes reductions for hedging transactions and letters of credits, as discussed under NPC’s and SPPC’s Financing Transactions.

NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, the Utilities may use their revolving credit facilities, in order to meet their liquidity needs. Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NVE and the Utilities have no significant debt maturities in 2010. Significant debt maturities in 2011 are limited to NPC’s $350 million 8.25% General and Refunding Notes, Series A, which mature on June 1, 2011. As of May 4, 2010, NPC has borrowed approximately $221 million on its $600 million revolving credit facility, and SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

NVE and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities. Furthermore, in order to fund long-term capital requirements, NVE and the Utilities will likely use a combination of internally generated funds, the Utilities’ revolving credit facilities, the issuance of long-term debt and/or equity and in the case of the Utilities capital contributions from NVE. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel, purchased power and operating costs 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, 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 delay capital expenditures, re-finance debt or issue equity at NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities utilization of their revolving credit facilities may be limited.

The Utilities credit ratings on their senior secured debt remain at investment grade (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.

As of May 4, 2010, NVE has approximately $21.4 million payable of debt service obligations remaining for 2010, which it intends to pay through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below).

NVE designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

During the three months ended March 31, 2010 there were no material changes to contractual obligations as set forth in NVE’s 2009 Form 10-K. However, in April 2010, the Utilities entered into new revolving credit facilities, as discussed under their respective sections, Financing Transactions.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of March 31, 2010, NVE (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $191.5 million of its unsecured 6.75% Senior Notes due 2017; and $230 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, 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, 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 March 31, 2010, NVE, NPC, SPPC and their subsidiaries had approximately $5.6 billion of debt and other obligations outstanding, consisting of approximately $3.8 billion of debt at NPC, approximately $1.3 billion of debt at SPPC and approximately $485 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that

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limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by 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 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. As a result of the Utilities’ credit rating on their senior secured debt at investment grade by S&P and Moody’s, these restrictions are suspended for as long as the debt remains investment grade by both 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 NVE could be jeopardized.

Credit Ratings

NVE, NPC and SPPC are currently rated by three Nationally Recognized Statistical Rating Organizations (NRSRO’s): Fitch, Moody’s and S&P. The senior secured debt of NPC and SPPC is rated investment grade by these three rating organizations. As of March 31, 2010, the ratings are as follows:

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

*Investment grade

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

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. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. 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, 2010 for all suppliers continuing to provide power under a WSPP agreement would approximate a $57.5 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as required by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion.

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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. 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 in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.

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. As of March 31, 2010, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $30.6 million. Of this amount, approximately $22.9 million would be required if NPC’s Senior Unsecured ratings are downgraded from their current level and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

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. As discussed under NPC’s and SPPC’s Financing Transactions, the Utilities shall reduce their availability under the Utilities’ revolving credit facilities is reduced for negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time be less than 50% of the total commitments then in effect under the credit facilities. As of May 4, 2010, the reduction to NPC’s and SPPC’s revolving credit facilities were $79.3 million and $25.2 million, based on mark-to-market values as of April 30, 2010. Currently, the Utilities only have hedging contracts with counterparties who are also lenders on the revolving credit facilities; however, future contracts entered into with non-lenders may require the Utilities to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, the Utilities have suspended their hedging program, and as such, expect their exposure to negative mark-to-market hedging transactions to decline.

Ability to Issue Debt

NV Energy, Inc.

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for 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 March 31, 2010, NVE (consolidated) would be allowed to incur up to $1.6 billion of additional indebtedness, assuming an interest rate of 7%. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.

Notwithstanding this restriction, under the terms of the debt, NPC and SPPC would still be 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, 2010, the combined total outstanding indebtedness and letters of credit under their respective revolving credit facilities was approximately $261 million not including any reductions for negative mark-to-market transactions. See NPC’s and SPPC’s Ability to Issue Debt sections for further discussion of the Utilities’ limitations on ability to issue debt.

If the applicable series of 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).

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 NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of 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

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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 NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC incurred a net loss of $12.3 million for the three months ended March 31, 2010 compared to a net loss of $35.2 million for the same period in 2009.

As of March 31, 2010, NPC had paid $27 million in dividends to NVE. On May 4, 2010, NPC declared an additional dividend of $26 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 energy 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, of 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.

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

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Operating Revenues	$	426,960	$	436,529		-2.2	%

Energy Costs:
Fuel for power generation		156,115		154,062		1.3	%
Purchased power		71,227		88,206		-19.2	%
Deferred energy - net		19,463		38,190		-49.0	%
	$	246,805	$	280,458		-12.0	%


Gross Margin	$	180,155	$	156,071		15.4	%

Gross margin increased in the first quarter of 2010, compared to the same period in 2009, primarily due to an increase in BTGR revenue as a result of NPC’s 2008 GRC, effective July 1, 2009. Partially offsetting the increase was a change in customer usage patterns which may be attributable to economic conditions and conservation programs and decreased transmission revenue as well as revenue associated with renewable energy programs.

The causes for 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).

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Operating Revenue

	Three Months Ended March 31,
					Change from
	2010		2009		Prior Year
Operating Revenues:
Residential	$	196,593	$	191,370		2.7	%
Commercial		94,269		96,794		-2.6	%
Industrial		119,648		128,039		-6.6	%
Retail revenues		410,510		416,203		-1.4	%
Other		16,450		20,326		-19.1	%
Total Operating Revenues	$	426,960	$	436,529		-2.2	%

Retail sales in thousands of MWhs		4,086		4,121		-0.8	%

Average retail revenue per MWh	$	100.47	$	101.00		-0.5	%

NPC’s retail revenues decreased for the three months ended March 31, 2010 as compared to the same period in 2009. The decrease in retail revenues is primarily due to the decrease in commercial and industrial revenues partially offset by the increase in residential retail revenue.

Commercial and Industrial retail revenues decreased primarily due to decreases in rates. Winter rates for time-of-use customers decreased as a result of NPC’s 2008 GRC, effective July 1, 2009. Also contributing to the decrease in rates were NPC’s various BTER quarterly cases and deferred energy cases (See Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2009 Form 10-K). These decreases were offset by a slight increase in the number of customers. The average number of commercial and industrial customers increased by 1.6% and 0.1%, respectively.

Residential retail revenues increased primarily due to increases in rates as a result of NPC’s 2008 GRC, with increases effective July 1, 2009, partially offset by decreased rates as a result of NPC’s various BTER quarterly cases and deferred energy cases (See Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2009 Form 10-K). The overall rate increase was offset by decreased customer usage due to changes in customer usage patterns and by a 0.4% decrease in the average number of residential customers.

Electric Operating Revenues – Other decreased compared to the same period in 2009. The decrease is primarily due to the expiration of a significant transmission agreement with Calpine Energy Services and decreases in sales for resale.

Energy Costs

Energy Costs include Fuel for 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 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 contracts; and
•		Mandated power purchases

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	Three Months Ended March 31, 2010
					Change from
	2010		2009		Prior Year
Energy Costs
Fuel for Generation	$	156,115	$	154,062		1.3	%
Purchased Power	$	71,227	$	88,206		-19.2	%
Energy Costs	$	227,342	$	242,268		-6.2	%

MWhs
Fuel for Generation (in thousands)		3,431		3,607		-4.9	%
Purchased Power (in thousands)		857		735		16.6	%
Total MWhs		4,288		4,342		-1.2	%

Average cost per MWh
Average fuel cost per MWh of Generated Power	$	45.50	$	42.71		6.5	%
Average cost per MWh of Purchased Power	$	83.11	$	120.01		-30.7	%
Average Cost per MWh	$	53.02	$	55.80		-5.0	%

Energy Costs decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to a decrease in hedging costs and a slight decrease in total system demand, partially offset by higher natural gas prices. The average cost per MWh for energy costs decreased primarily due to decreased hedging costs.

Fuel for generation costs increased primarily due to a change in method of allocating electric tolling option expense between fuel for generation and purchased power which had no impact on gross margin or operating income. Also contributing to the increase was an increase in the cost of natural gas prices. Partially offsetting these increases were decreased hedging costs and a decrease in volume due to an outage at the Higgins Generating Station.

·	Purchased power costs decreased primarily due to the change in method of allocating electric tolling option expense, as discussed above, and decreased hedging costs, slightly offset by an increase in volume.

Deferred Energy - Net

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Deferred energy - net	$	19,463	$	38,190		-49.0	%

Deferred energy – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy – net also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended March 31, 2010 and 2009 include amortization of deferred energy related primarily to the reinstatement of deferred energy and Western Energy Crisis rate cases of $8.2 million and $8.2 million, respectively; and an over-collection of amounts recoverable in rates of $11.3 million in 2010 and $30.0 million in 2009.

Other Operating Expenses

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Other operating expense	$	67,880	$	70,193		-3.3	%
Maintenance expense	$	17,019	$	27,534		-38.2	%
Depreciation and amortization	$	55,101	$	52,363		5.2	%

Other operating expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses and in 2009 higher legal costs; partially offset by higher outside consulting fees.

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Maintenance expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to planned maintenance outages that occurred in 2009 at the Clark, Reid Gardner and Silverhawk Generating Stations.

Depreciation and amortization increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to environmental upgrades and the completion of various distribution and transmission projects.

Interest Expense

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Interest expense (net of AFUDC-debt)	$	53,356	$	55,043		-3.1	%

Interest expense decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to lower interest on variable rate debt, credit facility balances, and the partial redemption of Series 1997A in December 2009. Also contributing to the decrease were lower interest on taxes, customer deposits, and the expiration in 2009 of amortization of costs related to debt issues and redemptions.

Partially offsetting this decrease was higher interest on long term debt related to the issuance of the following debt:

·	$125 million Series U General and Refunding Mortgage Notes in January 2009; and
·	$500 million Series V General and Refunding Mortgage Notes in March 2009.

Other Income (Expense)

	Three Months Ended March 31,
	2010			2009			Change from Prior Year

Interest income (expense) on regulatory items	$	(31	)	$	1,853			-101.7	%
AFUDC-equity	$	5,362		$	5,621			-4.6	%
Other income	$	2,583		$	2,342			10.3	%
Other expense	$	(1,132	)	$	(3,207	)		-64.7	%

Interest income (expense) on regulatory items decreased for the three months ended March 31, 2010 compared to the same period in 2009 due to over-collected deferred energy balances. See Note 3, Regulatory Actions, for further details of deferred energy balances.

AFUDC-equity decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to completion of various construction partially offset by construction at the Harry Allen Generating Station.

Other income increased for the three months ended March 31, 2010 compared to the same period in 2009 due to several items, none of which are individually material.

Other expense decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to costs recorded in 2009 for permits.

ANALYSIS OF CASH FLOWS

Cash From Operating Activities. The increase in cash from operating activities was primarily due to increased revenues as a result of the rate increase in NPC’s 2008 GRC, prepayment of taxes in 2009, reduced funding for pension plans and a reduction in spending for conservation programs and other regulated activities. These increases were partially offset by a reduction in BTER rates charged to customers, the timing of payments for property taxes and higher payments to vendors.

Cash Used By Investing Activities. Cash used by investing activities increased primarily due to ongoing construction at the Harry Allen Generating Station.

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Cash From Financing Activities. Cash from financing activities decreased primarily due to a reduction in draws on the revolving credit facility.

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 March 31, 2010 (in millions)
	NPC
Cash and Cash Equivalents	$	34.8
Balance available on Revolving Credit Facility (1)(2)		344.3

	$	379.1

(1)	NPC’s balance as of March 31, 2010 reflects amounts available under NPC’s $589 million revolving credit facility. In April 2010 NPC entered into a new revolving credit facility with a capacity of $600 million. See Financing Transactions below.
(2)	As of May 4, 2010, NPC had approximately $285.0 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NPC has no significant debt maturities in 2010. NPC’s significant debt maturities in 2011 are limited to its $350 million 8.25% General and Refunding Notes, Series A, which mature on June 1, 2011. As of May 4, 2010, NPC has borrowed approximately $221 million on its $600 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including recovery of deferred energy, and the use of its revolving credit facility. Furthermore, in order to fund long term capital requirements, NPC will likely use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE. However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters, 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, refinance 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 Utilities. As a result of 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 facilities.

In the first quarter of 2010, NPC paid dividends to NVE of approximately $27 million.

NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

During the three months ended March 31, 2010 there were no material changes to contractual obligations as set forth in NPC’s 2009 Form 10-K. However, in April 2010, NPC entered into a new revolving credit facility, as discussed under Financing Transactions.

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Financing Transactions

$600 Million Revolving Credit Facility

In April 2010, NPC terminated its $589 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $600 million secured revolving credit facility, maturing in April 2013. The fees on the $600 million revolving credit facility for the unused portion and on the amounts borrowed have increased reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, National Association (formerly Wachovia Bank, National Association). The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

Factors Affecting Liquidity

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 NVE debt. As of March 31, 2010, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $750 million in long term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long term debt or the use of the Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of March 31, 2010, NPC has financing authority from the PUCN to issue (1) additional long term debt of up to $750 million for the period ending December 31, 2010, (2) ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and (3) authority to refinance up to approximately $471 million of long-term debt securities.

b.	Financial covenants within NPC’s financing agreements – As stated in Financing Transactions above, NPC’s revolving credit facility agreement, dated November 2005, has been replaced with a new $600 million revolving credit agreement. Under the $600 million revolving credit facility, NPC must 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. Based on March 31, 2010 financial statements, NPC was in compliance with this covenant and could incur up to $1.7 billion of additional indebtedness.

	All other financial covenants contained in NPC’s financing agreements are suspended, as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and

c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.6 billion.

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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 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”).

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of March 31, 2010, $3.9 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $867 million of General and Refunding Mortgage Securities as of March 31, 2010. 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 NPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

Credit Ratings

NPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. As of March 31, 2010, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	BB	Not rated	BB+

* Investment grade

S&P’s and Moody’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member 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 may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. 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, 2010 for all suppliers continuing to provide power under a WSPP agreement would approximate a $57.5 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, 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 uses 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,

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which primarily means a credit rating downgrade below investment grade. 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 in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.

Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is reduced by the amount of negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time be exceed 50% of the total commitments then in effect under the revolving credit facility. As of May 4, 2010, the reduction to NPC’s revolving credit facility was $79.3 million based on mark-to-market values as of April 30, 2010. Currently, NPC only has hedging contracts with counterparties who are also lenders on the revolving credit facility; however, future contracts entered into with non-lenders may require NPC to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, NPC has suspended its hedging program as such expect its exposure to negative mark-to-market positions to decline.

Cross Default Provisions

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

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $17.1 million for the three months ended March 31, 2010 compared to net income of $19.1 million for the same period in 2009.

As of March 31, 2010, SPPC had paid $13 million in dividends to NVE. On May 4, 2010, SPPC declared an additional $12 million dividend to NVE.

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

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

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

	Three Months Ended March 31,
	2010			2009			Change from Prior Year
Operating Revenues:
Electric	$	209,981		$	237,738			-11.7	%
Gas		80,020			80,993			-1.2	%
	$	290,001		$	318,731			-9.0	%

Energy Costs:
Fuel for power generation	$	65,504		$	76,042			-13.9	%
Purchased power		36,136			37,181			-2.8	%
Gas purchased for resale		65,559			70,272			-6.7	%
Deferred energy – electric - net		(1,500	)		11,796			-112.7	%
Deferred energy – gas - net		(397	)		(4,351	)		-90.9	%
	$	165,302		$	190,940			-13.4	%
Energy Costs by Segment:
Electric	$	100,140		$	125,019			-19.9	%
Gas		65,162			65,921			-1.2	%
	$	165,302		$	190,940			-13.4	%

Gross Margin by Segment:
Electric	$	109,841		$	112,719			-2.6	%
Gas		14,858			15,072			-1.4	%
	$	124,699		$	127,791			-2.4	%

Electric gross margin decreased in the first quarter of 2010, compared to the same period in 2009, primarily due to a change in customer usage patterns which may be attributable to economic conditions and conservation programs, decreased revenues associated with renewable energy programs, and milder winter weather, partially offsetting these decreases was a slight increase in revenues from California customers.

Gas gross margin did not change materially for the first quarter of 2010, compared to the same period in 2009.

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

Electric Operating Revenue

	Three Months Ended March 31,
	2010		2009		Change from Prior year %
Electric Operating Revenues:
Residential	$	83,159	$	93,785		-11.3	%
Commercial		76,974		90,437		-14.9	%
Industrial		42,631		46,067		-7.5	%
Retail revenues		202,764		230,289		-12.0	%
Other		7,217		7,449		-3.1	%
Total Revenues	$	209,981	$	237,738		-11.7	%

Retail sales in thousands
MWh		1,960		1,980		-1.0	%

Average retail revenues per MWh	$	103.45	$	116.31		-11.1	%

SPPC’s retail revenues decreased for the three months ended March 31, 2010, as compared to the same period in 2009, primarily due to decreases in retail rates as a result of SPPC’s various BTER quarterly updates and the annual Deferred Energy case effective October 1, 2009. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K. The average number of residential and industrial customers decreased 0.2% and 1.9%, respectively, and the average number of commercial

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customers increased 0.1%. These decreases were offset by increased industrial usage primarily due to a gold mining customer which resumed operations in October 2009.

Electric Operating Revenues – Other decreased for the three month period ended March 31, 2010 compared to the same period in 2009 primarily due to decreased transmission revenues due to the expiration of several transmission service agreements.

Gas Operating Revenues

	Three Months Ended March 31,
	2010		2009		Change from Prior year %
Gas Operating Revenues:
Residential	$	42,363	$	45,881		-7.7	%
Commercial		20,482		21,840		-6.2	%
Industrial		5,939		5,892		0.8	%
Retail revenues		68,784		73,613		-6.6	%
Wholesale		10,561		6,734		56.8	%
Miscellaneous		675		646		4.5	%
Total Revenues	$	80,020	$	80,993		-1.2	%

Retail sales in thousands of Dths		5,985		6,107		-2.0	%

Average retail revenues per Dth	$	11.49	$	12.05		-4.7	%

SPPC’s retail gas revenues decreased in the three months ended March 31, 2010, compared to the same period in 2009, primarily due to decreases in retail customer rates and warmer temperatures in 2010. Retail rates decreased as a result of SPPC’s 2009 Natural Gas and Propane Deferred Rate Case and BTER quarterly updates. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K. The average number of retail customers increased by 0.6% for the three months ended March 31, 2010.

Wholesale revenues increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to excess supply resulting from lower customer usage.

Energy Costs

Energy Costs include Purchased Power and Fuel for Generation. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Purchased Power versus Fuel for Generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:

•		Weather
•		Plant outages
•		Total system demand
•		Resource constraints
•		Transmission constraints
•		Gas transportation constraints
•		Natural gas constraints
•		Long-term contracts
•		Mandated power purchases; and
•		Generation efficiency

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	Three Months Ended March 31,
					Change from
	2010		2009		Prior Year
Energy Costs
Fuel for Generation	$	65,504	$	76,042		-13.9	%
Purchased Power	$	36,136	$	37,181		-2.8	%
Total Energy Costs	$	101,640	$	113,223		-10.2	%

MWhs
Fuel for Generation (in thousands)		1,190		1,279		-7.0	%
Purchased Power (in thousands)		869		870		-0.1	%
Total MWhs		2,059		2,149		-4.2	%

Average cost per MWh
Fuel for Generation	$	55.05	$	59.45		-7.4	%
Purchased Power	$	41.58	$	42.74		-2.7	%
Total average cost per MWh	$	49.36	$	52.69		-6.3	%

Energy costs decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to a decrease in hedging costs, partially offset by increased natural gas costs.

·	The average cost per MWh for fuel for generation decreased in the three months ending March 31, 2010, primarily due to lower costs from hedging instruments partially offset by an increase in natural gas costs.
·	Purchase power costs, as a component of energy costs, and the average cost per MWh of purchased power decreased primarily due to higher resale of excess power, which are netted against purchased power costs.

Gas Purchased for Resale

	Three Months Ended March 31,
					Change from
	2010		2009		Prior Year

Gas Purchased for Resale	$	65,559	$	70,272		-6.7	%

Gas Purchased for Resale
(in thousands of Dth)		8,296		7,781		6.6	%

Average cost per Dth	$	7.90	$	9.03		-12.5	%

Gas purchased for resale decreased for the three months ended March 31, 2010, as compared to the same period in 2009. The decrease is primarily due to decreased costs associated with the settlement of hedging instruments partially offset by an increase in natural gas prices. Volume increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to excess availability of gas for wholesale customers.

Deferred Energy – Net

	Three Months Ended March 31,
	2010			2009			Change from Prior Year

Deferred energy – electric – net	$	(1,500	)	$	11,796			-112.7	%
Deferred energy - gas - net		(397	)		( 4,351	)		-90.9	%
Total	$	(1,897	)	$	7,445

Deferred energy – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy – net also include the current amortization of fuel and purchased power costs previously deferred Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, for further detail of deferred energy balances.

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Deferred energy - electric – net for the three months ended March 31, 2010 and 2009 reflect amortization of deferred energy of ($5.8) million and ($0.8) million, respectively; and an over-collection of amounts recoverable in rates of $4.3 million and $12.6 million respectively.

Deferred energy - gas - net for the three months ended March 31, 2010 and 2009 reflect amortization of deferred energy of ($3.5) million, and $0 million, respectively; and an over-collection of amounts recoverable in rates in 2010 of $3.1 million and an under-collection of $4.4 million in 2009.

Other Operating Expenses

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Other operating expense	$	40,672	$	44,015		-7.6	%
Maintenance expense	$	8,710	$	6,866		26.9	%
Depreciation and amortization	$	25,847	$	25,685		0.6	%

Other operating expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses and lower costs associated with renewable energy programs; partially offset by higher outside consulting fees.

Maintenance expense increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to scheduled combustion turbine maintenance at the Tracy Generating Station.

Depreciation and amortization increased slightly for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to regular system growth in plant-in-service.

Interest Expense

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Interest expense (net of AFUDC-debt)	$	17,045	$	17,927		-4.9	%

Interest expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to lower interest rates on variable rate debt, interest savings related to repurchased debt, lower interest on credit facility balances, the partial redemption of $73.3 million of the $325 million Series P General and Refunding Mortgage Bonds in December 2009, and interest on taxes in 2009. These amounts were partially offset by the issuance of $150 million of 6.0% Series M General and Refunding Mortgage Notes in August 2009. See Note 4, Long-Term Debt, of the Notes to Financial Statements of the 2009 Form 10-K for additional information regarding long-term debt.

Other Income and (Expenses)

	Three Months Ended March 31,
	2010			2009			Change from Prior Year

Interest income (expense) on regulatory items	$	(2,040	)	$	(673	)		203.1	%
AFUDC-equity	$	591		$	597			-1.0	%
Other income	$	1,755		$	2,715			-35.4	%
Other expense	$	(1,869	)	$	(1,991	)		-6.1	%

Interest income (expense) on regulatory items increased for the three months ended March 31, 2010, compared to the same period in 2009, due to higher over-collected deferred energy balances in 2010.

AFUDC-equity slightly decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to a decrease in construction.

Other income decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to interest received for tax refunds in 2009, partially offset by interest income from investments in 2010.

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Other expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, due to several items, each of which is not materially significant.

ANALYSIS OF CASH FLOWS

Cash flows increased during the three months ended March 31, 2010, compared to the same period in 2009, primarily due to a reduction in cash used by investing activities and an increase in cash from operating activities, partially offset by an increase in cash used by financing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to higher payments to vendors in the first quarter of 2009 and the timing of interest payments. These increases were partially offset by lower revenues as a result of BTER rate reductions, the timing of property tax payments, funding of pension plans and spending for conservation programs.

Cash Used By Investing Activities. Cash used by investing activities decreased due to the slowdown in construction for infrastructure.

Cash Used By Financing Activities. The increase in cash used by financing activities is primarily due to a reduction in draws on SPPC’s revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’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 SPPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.

Available Liquidity as of March 31, 2010 (in millions)
	SPPC
Cash and Cash Equivalents	$	28.5
Balance available on Revolving Credit Facility (1)(2)		316.2

	$	344.7

(1)	SPPC’s balance as of March 31, 2010 reflects amounts available under SPPC’s $332 million revolving credit facility. In April 2010 SPPC entered into a new revolving credit facility with a capacity of $250 million. See Financing Transactions below.
(2)	As of May 4, 2010, SPPC had approximately $208.5 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, SPPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

SPPC has no significant debt maturities in 2010 or 2011. As of May 4, 2010, SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facilities. Furthermore, in order to fund long-term capital requirements, SPPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facilities, the issuance of long-term debt, and capital contributions from NVE. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, re-finance debt or obtain funding through an equity issuance by NVE.

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debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

In the first quarter of 2010, SPPC paid dividends to NVE of $13 million.

SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

During the three months ended March 31, 2010 there were no material changes to contractual obligations as set forth in SPPC’s 2009 Form 10-K. However, in April 2010, SPPC entered into a new revolving credit facility, as discussed under Financing Transactions.

Financing Transactions

$250 Million Revolving Credit Facility

In April 2010, SPPC terminated its $332 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $250 million secured revolving credit facility, maturing in April 2013. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have increased reflecting current market conditions. The Administrative Agent for the facility is Bank of America, N.A.. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The SPPC Credit Agreement contains one financial maintenance covenant that 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. In the event that SPPC did not meet the financial maintenance covenant or there is an event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

Factors Affecting Liquidity

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 NVE debt. As of March 31, 2010, the most restrictive of the factors below is the PUCN authority. Based on this restriction, SPPC may issue up to $350 million of long term debt securities, and maintain a credit facility of up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below.

a.	Financing authority from the PUCN - As of March 31, 2010, SPPC has financing authority from the PUCN to issue (1) additional long term debt of up to $350 million for the three-year period ending December 31, 2012, (2) ongoing authority to maintain a revolving credit facility of up to $600 million, and (3) authority to refinance approximately $348 million of long-term debt securities.

b.	Financial covenants within SPPC’s financing agreements – As stated in Financing Transactions above, SPPC’s revolving credit facility agreement, dated November 2005, has been replaced with a new $250 million revolving credit agreement. Under the $250 million revolving credit facility, SPPC must 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. Based on March 31, 2010 financial statements, SPPC was in compliance with this covenant and could incur up to $855 million of additional indebtedness.

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

c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.6 billion.

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 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”).

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of March 31, 2010, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $606 million of General and Refunding Mortgage Securities as of March 31, 2010. 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 SPPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

Credit Ratings

SPPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NVE and the Utilities. As of March 31, 2010, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

* Investment grade

S&P’s and Moody’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

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Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. 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. Under the net mark-to-market value as of March 31, 2010 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 6, 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, SPPC uses 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 change, 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. 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 counterparties require payment in advance of delivery.

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under SPPC’s Financing Transactions, the availability under SPPC’s revolving credit facility is reduced by the amount of negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. As of May 4, 2010, the reduction to SPPC’s revolving credit facility was $25.2 million based on mark-to-market values as of April 30, 2010. Currently, SPPC only has hedging contracts with counterparties who are also lenders on the revolving credit facility; however, future contracts entered into with non-lenders may require SPPC to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, SPPC has suspended its hedging program as such expect its exposure to negative mark-to-market positions to decline.

Cross Default Provisions

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

REGULATORY PROCEEDINGS (UTILITIES)

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

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

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

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover or refund any under or over collection of prior energy costs and the BTER Updates recover current energy costs. As of March 31, 2010, NPC’s and SPPC’s balance sheets included approximately $40.1 million and credits of $118.6 million, respectively, of deferred energy costs of which $56.9 million and credits of $108.8 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

Rate case applications filed in 2009 and 2010, as well as other regulatory matters such as, the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and in the 2009 Form 10-K.

RECENT PRONOUNCEMENTS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2010, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. The tables below do not include the interest rate swap entered into in 2009 and discussed further in Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, as the amount is considered immaterial. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

	March 31, 2010
	Expected Maturity Date
																					Fair
	2010		2011			2012			2013			2014			Thereafter			Total			Value
Long-Term Debt
NVE
Fixed Rate	$	-	$	-		$	63,670		$	-		$	230,039		$	191,500		$	485,209		$	495,056
Average Interest Rate		-		-			7.80	%					8.63	%		6.75	%		7.78	%

NPC
Fixed Rate	$	-	$	364,000		$	130,000		$	-		$	125,000		$	2,717,050		$	3,336,050		$	3,590,974
Average Interest Rate		-		8.14	%		6.50	%		-			7.38	%		6.50	%		6.72	%
Variable Rate	$	-	$	-		$	-		$	230,000		$	-		$	173,775		$	403,775		$	403,775
Average Interest Rate		-		-			-			0.99	%		-			0.67	%		0 .85	%

SPPC
Fixed Rate	$	-	$	-		$	100,000		$	250,000		$	-		$	701,742		$	1,051,742		$	1,135,913
Average Interest Rate		-		-			6.25	%		5.45	%		-			6.27	%		6.07	%
Variable Rate	$	-	$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	214,675
Average Interest Rate		-		-			-			-			-			0.64	%		0.64	%

Total Debt	$	-	$	364,000		$	293,670		$	480,000		$	355,039		$	3,998,742		$	5,491,451		$	5,840,393

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Commodity Price Risk

See the 2009 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2009.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $62.9 million as of March 31, 2010, which compares to balances of $73.2 million at December 31, 2009. The decrease from December 31, 2009 is primarily due to the decrease in prices of natural gas and power during the first quarter of 2010.

ITEM 4 and 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of March 31, 2010, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the first quarter of 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

NPC and SPPC

Western United States Energy Crisis Proceedings before the FERC

FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the FERC’s July decision and remanded the case back to the FERC for application of factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation, Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that the FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC.

The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy Supply Company, American Electric Power Service Corporation and BP Energy, and stayed the case pending settlement discussions. The Utilities, together with other interested parties including the Nevada BCP, have settled and resolved all claims against BP Energy (“BP Settlement”). On August 25, 2009, the BP Settlement received final approval by the FERC, under which BP Energy was ordered to settle with NPC for an immaterial amount in return for NPC and the BCP’s release of all claims against BP Energy. On November 19, 2009, the Utilities, together with other interested parties, executed a settlement agreement with American Electric Power Service Corporation (“AEP Settlement”). On December 23, 2009, the AEP Settlement received final approval by the FERC, under which AEP was ordered to settle with the Utilities for an immaterial amount in return for a release of all claims by the Utilities and BCP against AEP. This amount was received in February 2010 from AEP in fulfillment of its

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obligations under the settlement agreement. The Utilities had previously negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron. The Utilities continue discussions under FERC settlement procedures with Allegheny Energy Supply Company. Management cannot predict the timing or outcome of a decision in this matter.

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements, for further discussion of other legal matters.

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2009 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2009 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 5. OTHER INFORMATION

The following information was not required to be disclosed on Form 8-K during the period covered by this Form 10-Q, but is instead being included to update the Registrants’ environmental disclosure in Part I, Item 1, of the 2009 Form 10-K, under the caption “Federal Environmental Laws, Regulations and Regulatory Initiatives”.

Regulatory Developments Pertaining to Climate Change

On April 1, 2010, the EPA and the National Highway Traffic Safety Administration (NHTSA) released their final Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards (Motor Vehicle Rule). The standards set the first standards on carbon dioxide (CO2) and other greenhouse gas (GHG) emissions from certain cars and trucks.

By regulating mobile sources under the Clean Air Act, the Rule may also trigger an increase in permitting requirements, including emission limits on new and modified stationary sources, under the Act. Specifically, when it takes effect on January 2, 2011, the rule may trigger Prevention of Significant Deterioration (PSD) and Title V permitting requirements for several million stationary sources. EPA will address whether, and if so, when and how stationary sources may be subject to PSD because of GHG emissions in its “Tailoring Rule,” 74 Fed. Reg. 55291, which was proposed on October 27, 2009, and is expected to be finalized later this Spring. We note that new energy and carbon legislative proposals are also currently pending in Congress and, if such bills were passed, could supersede EPA proposals to regulate carbon associated with electric utility stationary sources.

While the Utilities cannot predict the final form these regulations or bills will take or the specific cost implication to our stationary facilities at this time, the Utilities continue to closely monitor developments.

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ITEM 6.EXHIBITS

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

(10) NV Energy, Inc.:

10.1

Assistance Agreement dated March 12, 2010 between the U.S. Department of Energy and NV Energy, Inc.

(12) NV Energy, Inc.:

12.1

Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company:

12.2

Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company:

12.3

Statement regarding computation of Ratios of Earnings to Fixed Charges.

(31) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

31.1		Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

31.4		Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

(32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

32.1		Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

32.4		Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

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SIGNATURES

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


	NV Energy, Inc.
	(Registrant)


Date: May 5, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Interim Chief Financial Officer
		(Principal Financial Officer)

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


Date: May 5, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Interim Chief Financial Officer
		(Principal Financial Officer)

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

Date: May 5, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Interim Chief Financial Officer
		(Principal Financial Officer)

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NEVADA POWER CO - FORM 10-Q - May 5, 2010

Attached files

NEVADA POWER CO Reports